Friday, December 29, 2017

South Korea Seizes Ship Suspected Of At-Sea Oil Transfer To Benefit North Korea

South Korea has seized a Hong Kong-flagged vessel under suspicions that it illegally transferred oil to North Korea, in violation of U.N. sanctions. The vessel, the Lighthouse Winmore, was seized one month after it allegedly ferried oil, South Korean media report.

Such ship-to-ship transfers are prohibited by a U.N. Security Council Resolution that was adopted in September, part of a suite of sanctions that target North Korea over its nuclear and missile programs.

The seizure and inspection took place in November, but it was reported only after South Korea's Chosun Ilbo newspaper published U.S. reconnaissance photos on Tuesday that were part of a U.S. Treasury Department announcement of sanctions on 20 North Korean vessels and six shipping and trading companies. The U.S. sanctions cited suspected ship-to-ship transfers of oil in international waters.

The Chosun Ilbo reports that U.S. reconnaissance images had shown "Chinese ships selling oil to North Korean vessels on the West Sea around 30 times since October."

When the Treasury Department released reconnaissance images of an Oct. 19 rendezvous between two ships, the agency named the North Korean ship as the Rye Song Gang 1 — and included an image clearly showing the name on the vessel's hull. It did not identify the other, much larger, ship.

Citing South Korean officials, the Yonhap news agency reports that the Lighthouse Winmore is suspected of transferring 600 tons of refined petroleum to a North Korean vessel on Oct. 19. The ship was seized in late November after it came into South Korea's port in Yeosu. It reportedly remains in custody.

From Yonhap:
"The Hong Kong-flagged ship was chartered by Taiwanese company Billions Bunker Group and previously visited South Korea's Yeosu Port on Oct. 11 to load up on Japanese refined oil and head to its claimed destination in Taiwan, the authorities noted.
"Instead of going to Taiwan, however, the vessel transferred the oil to a North Korean ship, the Sam Jong 2, and three other non-North Korean vessels in international waters, they said."
After the reconnaissance photos were publicized, President Trump tweeted, "Caught RED HANDED - very disappointed that China is allowing oil to go into North Korea. There will never be a friendly solution to the North Korea problem if this continues to happen!"

On Friday, China's Foreign Ministry spokesperson Hua Chunying said that charges of Chinese ships sending oil to North Korea "do not accord with facts."

As state-run Xinua media reports, "Hua said that China had immediately investigated the relevant ship and found that it has not docked in any Chinese ports and had no entry and departure records of Chinese ports since August."

The U.S. has repeatedly called China a pivotal player in the effort to convince North Korea to rein in its nuclear program and ease tensions on the Korean Peninsula. Earlier this week, Secretary of State Rex Tillerson called on China to "exert its decisive economic leverage on Pyongyang."

Writing an op-ed piece for The New York Times, Tillerson added, "China has applied certain import bans and sanctions, but it could and should do more."

Thursday, December 28, 2017

In Bad Trade Off, New England Forsakes Natural Gas For Petroleum

In New England, an overall concern for the environment and safety has actually led to further risks to the environment.
Opponents of a proposed natural gas pipeline protest on Boston Common across from the Statehouse in Boston, Wednesday, July 30, 2014. (AP Photo/Charles Krupa)

New England has been at the forefront of converting its fossil fuel power plants to use cleaner burning natural gas. In fact, the region’s electricity generation is over 50% reliant on natural gas. In addition, many New Englanders have gas lines in their homes and use natural gas for heating and cooking.

However, natural gas prices in New England are also the most expensive in the nation, because state and local governments have fought to keep out the pipelines needed to transport it into and around the region. Natural gas prices across the United States dropped with the advent of fracking, and it would be easy and cheap to supply New England with natural gas from the nearby Marcellus shale region. Several companies have tried to build pipelines to bring this gas to New England, but they were stymied by hostile local governments and ultimately by a 2016 ruling from the Supreme Judicial Court of Massachusetts that forbade utility companies from entering into long term natural gas deals with the intent of passing on charges to customers. After the legal case was decided in Massachusetts, Kinder Morgan KMI +0.06% withdrew plans for a new pipeline.

Ice coats a small branch as temperatures drop across the New England region (Shutterstock)

Now, a polar vortex has hit the northeast and frigid temperatures are causing demand for natural gas to skyrocket . Natural gas prices in New England tripled in just one day and are currently some of the highest in the nation. Now New England has turned to petroleum, a source of great pollution and even greater expense, for electricity generation. Over the course of one day, December 27, 2017, petroleum use grew from less than 500MW to nearly 4,000MW. Petroleum accounted for 22% of the electricity generation, just behind nuclear at 35% and natural gas at 24%.

Ellen R. Wald, Ph.D. is a historian & consultant on geopolitics & energy. She is a Non-Resident Scholar at the Arabia Foundation. Her book, Saudi, Inc., will be published in 2018.

Friday, December 22, 2017

Oil dips from highs but OPEC cuts still support market

Oil prices dipped on Friday but stayed near their highest levels since 2015 on pledges from OPEC leader Saudi Arabia and non-OPEC Russia that any exit from crude output cuts would be gradual. 

Market liquidity was drying up on Friday as traders closed positions ahead of the Christmas and New Year breaks. 

Brent crude futures, the international benchmark for oil prices, were down 24 cents at $64.66 a barrel at 1158 GMT, after ending Thursday at $64.90, its highest close since June 2015. 

U.S. West Texas Intermediate (WTI) crude futures were at $58.05 a barrel, down 31 cents. WTI has also been touching values not seen since mid-2015 over the past two months. 

Oil prices have recovered in the past year on the back of oil production cuts by OPEC, Russia and other producers, helping reduce the global inventory overhang. 

Russian Energy Minister Alexander Novak told Reuters OPEC and Russia would exit cuts smoothly, possibly extending curbs in some form to avoid creating any new surplus. 

“There is a consensus among the (oil) ministers that we should avoid oversupply on the market when exiting the deal,” Novak said, comments that will calm investor worries that Moscow wants a speedy exit. 

Saudi Energy Minister Khalid al-Falih said it was premature to discuss changes to the pact on supply cuts as market rebalancing was unlikely to happen until the second half of 2018. 

The OPEC-led pact to withhold supplies started in January this year. The producer group and its allies agreed to extend the cuts cover all of 2018 from their March expiry. 

The supply restraint has reduced oil inventories and helped push up Brent by more than 45 percent since June this year. 

“OPEC’s extension of its production cuts through the end of 2018 is a necessary condition for continued inventory drawdown,” U.S. investment bank Jefferies said, raising its 2018 Brent forecast to $63 from $57, and its WTI forecast to $59 from $54. 

Novak said some pressure on prices was possible in the first quarter of 2018 when demand traditionally declines and added he saw prices hovering at around $50 to $60 in 2018. 

Analysts said crude output in the United States, fast approaching 10 million bpd, would be a drag on prices in the longer term. 

“Supply is expected to grow further, paving the way to an oversupplied market, which can again exercise downward pressure on oil prices,” consultancy Rystad Energy said. 

Novak said he expected U.S. oil output to grow by 0.6 million bpd in 2018 but added that rising U.S. demand should help offset an increase. 

Editing by Edmund Blair

Thursday, December 21, 2017

Nigerian Oil Supply Eases
  • Nigerian oil worker talks will continue in January: Pengassan
  • Repairs to cracked North Sea oil pipeline proceeding to plan
Crude lingered near $57 a barrel for a third day as oil workers in Nigeria suspended a strike and repairs to a crucial North Sea pipeline proceeded apace.

Futures slipped 0.2 percent in New York, erasing gains from earlier in the session. Managerial workers in Africa’s second-largest crude-producing nation halted their strike and agreed to reopen talks next month. Meanwhile, the owner of the Forties Pipelines System in the North Sea, which helps set international oil prices, said repairs to a crack that halted shipments a week ago were on track.

“People that bought on the word of the strike are probably taking some profits,” said Phil Flynn, senior market analyst at Price Futures Group Inc. in Chicago.
The Nigerian oil union known as Pengassan stopped work after talks deadlocked late Sunday, according to a spokesman. The union, the labor minister and Neconde Energy Ltd. will restart talks in January.

A hairline crack which prompted Ineos Group to shut its Forties system on Dec. 11 “has not propagated,” the company said in an email. Repairs are expected to be complete within weeks. Hedge-fund managers have amassed a record number of bullish wagers on London crude prices, creating conditions that could trigger a selloff as the Forties restart date approaches, said Bob Yawger of Mizuho Securities USA.

Unwinding Positions

“The only thing that’s holding the market here at these levels is the Forties problem,” said Yawger, Mizuho’s New York-based director of futures. “The potential is there for people to start bailing on the loaded-up speculative position. I would tend to think there will be a slow unwinding of these positions in anticipation” of the line restarting soon.

Oil in New York is poised for about a 6 percent gain this year as production limits by the Organization of Petroleum Exporting Countries and other major suppliers erode a worldwide glut. The effort to curb excess output could be dashed by U.S. shale drillers, who are forecast to lift American oil production to a record next year.

West Texas Intermediate for January delivery, which expires Tuesday, dropped 14 cents to settle at $57.16 a barrel on the New York Mercantile Exchange. Total volume traded was about 23 percent below the 100-day average.

Brent for February settlement rose 18 cents to end the session at $63.41 on the London-based ICE Futures Europe exchange. The global benchmark traded at a premium of $6.19 to February WTI.

The Brent net-long position -- the difference between bets on a price increase and wagers on a drop -- rose 1.8 percent to a record 544,051 contracts in the week ended Dec. 12, according to data from ICE Futures. Longs increased for a third week, also reaching an all-time high. During the same period, bullish bets on WTI were near a nine-month high.
Oil-market news:
  • The Energy Information Administration sees crude output at major U.S. shale plays reaching 6.41 million barrels a day in January, according to a monthly Drilling Productivity Report.
  • Cushing, Oklahoma, crude stockpiles dropped by 2.2 million barrels last week, according to a forecast compiled by Bloomberg.
  • This year is shaping up to be the worst for oilfield servicers since 2008, when the global financial crisis roiled markets and industries everywhere.
  • Saudi Arabia’s crude oil exports rose to 6.874 million barrels a day in October, according to the JODI-Oil World Database.
— With assistance by Ben Sharples, and Grant Smith

Wednesday, December 20, 2017

Oil and gold looking a little bit more “normal” as 2017 draws to a close

A few weeks ago in London, at a pre-conference dinner before the Platts Digital Commodities Summit, the conversation naturally turned to bitcoin and other cryptocurrencies, and the rejection – and disdain – that many supporters of the entire crypto movement have for what are known as “fiat currencies.” Most people know fiat currencies as everything from afghanis (Afghanistan) to zlotys (Poland), with dollars, yen and euros in-between. 

Crypto currencies have been likened to gold: not controlled by a central government, a supply that rises only incrementally (and in the case of bitcoin, will eventually be capped), and therefore not inflationary. One of the conversation’s participants in the restaurant’s cigar bar, a backer of bitcoin, said to another person: “Look at that suit you’re wearing. I’ll bet you 200 years ago, if you had bought the equivalent suit and paid for it in gold, it would cost you the same amount in gold then as it would today.” Gold isn’t volatile against the dollar, he said. The dollar is volatile against gold.

S&P Global Platts has a price database of many things. It doesn’t have one of men’s suits, so it is tough to confirm the relationship. But every year at this time, we take a look at the price of oil through the prism of how much gold it would take to buy a barrel of oil. 

Last year, we suggested that changes in the fundamentals of oil may have moved the normal relationship between the two commodities to a higher number. Our 34-year comparison of gold and oil — which commences in 1984 with WTI, as that data goes back further than that of Brent — averaged 16.65 through 2016. That is somewhat higher than the conventional wisdom that the ratio of oil to gold—the number of barrels of oil needed to buy an ounce of gold—has a “norm” of 15. From the start of 2003, the average is much closer to 15, standing at 15.41. 

The problem is that within that norm, there are vast swings. Our data shows the ratio dropping to as low as 7 (2008 oil price surge), and as high as 40 (oil price crash, February 2016). 

Given that in the price crash of ’98-’99, gold was crashing right along with oil and the ratio never got much above 20, could it be that the significant change in drilling technologies over the past few years means that the 15 number is no longer valid, as evidenced by it blowing out to 40 at its most extreme? We suggested that after the average for 2016 hit 29.54, more than 5 “points” above the 2015 level. The writer of last year’s blog — OK, it was me — declared that it was possible that the shale revolution had moved oil to a permanent wider discount to gold. 

There has been no hint of that “normal” ratio since the price of oil began falling in 2014. The average ratio in 2015 was 24.18; in 2016, it was 29.54. The average for 2017 through December 14 is slightly more than 25, so not that much different than it was two years ago. Halfway through the year, the six-month average was just less than 25.

Oil vs gold 2017

It is true as the year comes to a close that the ratio has moved closer toward that theoretical norm, but it still has a ways to go. Even with the price of WTI tacking on $12 from its midyear level, the ratio at the end of the year was just under 22. Part of the reason it didn’t fall more is that gold has risen from the middle of the year as well, adding about $30 to a level of about $1,250 on December 14. 

Even if gold stayed flat and WTI went to $70, the ratio would decline to only a bit under 18. And such a situation is almost impossible to fathom; if oil were to go up $15 from here, gold is not just going to sit unchanged.

It’s clear that the blowout numbers of 2016 in this ratio were an aberration. It also seems true that there are going to need to be some big unexpected shift in oil markets, financial markets, or both, to get this spread down toward normal. And maybe that means there’s a new normal.


John Kingston, Director of Global Market Insights
John Kingston is the Director of Global Market Insights for S&P Global, Platts parent company. He assumed that role in early 2015 after almost 30 years with Platts. In his role, he provides leadership and coordination with the company’s team of economists around the world, and with experts on key issues of relevance to S&P Global across its business units. He also continues to keep his eye on developments in the energy world.

Tuesday, December 19, 2017

Ethanol Trade between the U.S. & China Spikes in Wake of Price Drop

Since early October, it has been reported that the fuel ethanol arbitrage window from the U.S. to China has officially opened. This comes after the Chinese government implemented a hefty 30 percent import tariff in January of 2017 in an attempt to boost domestic corn and ethanol production. There are 11 provinces and 40 cities that currently have a 10 percent ethanol blend rate mandate, but China has announced a timeline for implementing the mandate across the country by 2020. Chinese domestic policy also dictates that almost all of the ethanol used must be domestically produced, according to the U.S. Department of Agriculture. China was one of the top buyers of American fuel ethanol in 2016, comprising of approximately 17 percent of all exports according to U.S. Census Bureau data.

Initially, many analysts and traders believed that there would not be any fuel ethanol trade between the U.S. and China with this tariff in effect. From the time the tariff was put in place through October 2017, almost no ethanol from the U.S. shipped to China according to U.S. Census Bureau data. However, with current U.S. ethanol prices as low as $1.30/gallon, exporting fuel ethanol to China is now very attractive, even with the tariff in place.

U.S. Fuel Ethanol Exports
Total U.S. fuel ethanol exports compared to U.S. exports to China from 2014 to 2017. *2017 data through October. Data source: U.S. Census Bureau Trade Data

With the arbitrage window open, when will shipments begin moving ethanol to China and from where? 

Two shipments out of Oiltanking Texas City in Texas City, TX, and one from Kinder Morgan’s Delta Terminal in Harvey, LA, are currently en route to Ningbo and Nanjing, China. Genscape also saw that the vessel “Beatrice” out of Oiltanking Texas City changed its original destination from South Korea to China. All three shipments are expected to arrive in China before the end of the year.

Genscape Vesseltracker Track
Genscape Vesseltracker’s data shows that three shipments have left the U.S. Gulf Coast loaded with ethanol and are headed to China. Click to enlarge
Ethanol production has not shown a slowdown, and storage levels are still high, supporting ethanol exports from the U.S. With Brazil’s 20 percent tariff quota in place, additional export destinations are needed to keep pace with U.S. ethanol production. Various destinations such as India, Spain, and Nigeria have replaced the volume that may have been shipped to Brazil. However, while ethanol prices are still low, it appears that U.S. ethanol exports to China will remain attractive throughout the end of the year.

Genscape will continue to track the movements of future ethanol shipments to China and the current production levels. To receive the latest information on U.S. ethanol exports from the Gulf Coast, including daily storage measurements of terminals known to export ethanol, ethanol volumes loaded to vessels, and up-to-date vessel destinations, please click here to learn more about Genscape’s Ethanol Exports Monitor.

Monday, December 18, 2017

What Will Global Oil Storage Balances Look Like In 2018?

Oil prices started the week pulling back from last week's OPEC frenzy. On the news front, there wasn't anything meaningful other than the fact that China's crude oil imports of 9.05 million b/d for November was the second highest on record.

In our weekly oil storage report this week, we noted that the balance towards the end of the year will be very positive (crude draws wise). In addition, Cushing balances have been drawing as issues in TransCanada Keystone was limited in flow due to a spillage.

Normally, as you will see in the chart below, Cushing balances build into year-end as refineries park inventories in Cushing and other areas to lower tax liabilities. That won't be the case this year with TransCanada's Keystone outage lowering flows.

So, going into year-end 2017, US crude storage will draw, and with total liquid stockpile's year-over-year comparison accelerating to the downside, what does that mean for global oil balances in 2018?

Global Oil Storage Balances in 2018

The big worry for the consensus at the moment is - what happens to global oil storage balances in the first three months (Q1) of 2018?

On average from the data we have compiled, consensus is estimating somewhere around ~400k b/d of storage builds globally. The input to arrive at a build is that non-OPEC supplies driven in large part by 1) US shale and 2) Canada.

From our global oil storage balance analysis, the assumptions for a storage build in Q1 2018 appear to be standing on thin ice. One of our contributors, Open Square Capital, has already discussed this in this article, "Oil Inventories Early 2018: Why The Consensus Is Out Of Touch."

Now this is not us bashing Goldman or anything, but in an oil market report they published in October, they had Q4 2017 reporting a build, which from all angles of analysis, it was as a bad forecast as saying something is blue when it's clearly green. But we digress, they are now expecting a draw in Q4 2017, two months into Q4 (thumbs up Goldman).

But will global storage actually build to the tune of ~500k b/d like Goldman thinks?

The issue with an estimate like the one provided by Goldman is that a build of 500k b/d can swing easily into a deficit. For example, Goldman has US oil production sitting at 9.925 million b/d in Q1 2018. A 100k to 200k b/d swing either way would push global storage estimates to a range of +300k b/d to +700k b/d.

Then we have Brazil, which Goldman is currently forecasting at ~2.8 million b/d, when October production figures just came in at ~2.63 million b/d.

 What we find interesting amongst the consensus is that global, identified storage draws are now averaging right around ~-1 million b/d for Q4 2017. We know demand normally drops 600k to 700k b/d in Q1, so for global storage to average a build of ~+400k b/d, we would need a supply increase of 700k to 800k b/d.

Is that realistic? We will let you decide.

Thank you for reading. For those who have found our public oil market articles insightful, we want to let you know about a unique opportunity. You can sign up for HFI Research before Jan. 1 and lock in our current rates before they move higher in 2018. Readers have found our work "indispensable and highly addictive," and if you like these articles, we know you will find our exclusive reports to be even more helpful.

Friday, December 15, 2017

Cuba takes over Venezuela stake in refinery joint venture

HAVANA/HOUSTON, Dec 14 (Reuters) - Venezuela has pulled out of a partnership with Cuba in its Cienfuegos oil refinery and the Caribbean island has taken full ownership of the plant, Cuban state media said on Thursday. 

Venezuela is grappling with a crippling economic crisis that already forced it to slash cheap oil shipments to Cuba, which has had a knock-on effect on the island’s ailing economy. 

The reason for the dissolution of the partnership was not immediately obvious. A former Venezuelan government official said Cuba had taken Venezuelan state oil-firm PDVSA’s 49 percent stake in the Cienfuegos refinery as payment for debts it said the country incurred.
The source added that Cuba said Venezuela owed it for professional services provided as well as the rental of tankers. 

PDVSA’s Cuba unit was unable to provide immediate comment. Cuba’s state-run oil monopoly Cubapetroleo (Cupet), which runs the refinery, did not respond to a request for comment. 

“Since August 2017, the Cienfuegos refinery has been operating as a fully Cuban state entity,” the ruling Communist Party’s newspaper Granma wrote. 

The Cienfuegos refinery is a Soviet-era facility configured to run Russian crude that was later upgraded by PDVSA to convert up to 65,000 barrels per day (bpd) of Venezuelan oil into refined products for Cuba’s domestic market and exports. 

It processed just 8 million barrels of crude in 2017 (roughly 24,000 barrels per day), Granma reported, indicating it was operating well below capacity due to lower shipments of oil from Venezuela. 

A lack of medium and light oil had forced PDVSA this year to change the quality of the crude shipped to the island to heavier grades, which are more difficult to process at Cienfuegos. 

Cuba has long relied on the OPEC nation for about 70 percent of its fuel needs. But shipments have fallen by as much as 40 percent since 2014 and Cuba is looking for new suppliers to help mitigate electricity and fuel rationing to state companies. 

Cuba took a delivery of oil from Russia in May, helping compensate somewhat for that drop, and Russian oil major Rosneft said in October it was looking to expand cooperation. 

That could mean increased deliveries to Cuba, joint extraction projects as well as cooperation to modernize the Cienfuegos refinery, Rosneft said. 

Venezuela remains Cuba’s top ally and President Nicolas Maduro was due to stop off in Havana on Thursday as he returned from a conference in Turkey, newspaper El Nacional reported. 

Still, lower Venezuela oil supplies and a cash crunch have forced Cuba to slash imports and reduce the use of fuel and electricity over the past two years. 

This helped tip its centrally planned economy into recession in 2016 for the first time in nearly a quarter century. The government is expected to give an estimate for economic performance this year at the twice-annual parliamentary session next week. (Reporting by Sarah Marsh in Havana and Marianna Parraga in Houston; Editing by Andrew Hay)

Wednesday, December 13, 2017

The Noose Tightens: Venezuela Struggles To Ship Oil

The picture for Venezuela grows grimmer by the day, as tankers waiting to load fuel oil from Venezuela ports grow in number as the national oil company, PDVSA, struggles to deliver the amounts needed to load. That’s what traders and shipping data from Reuters have revealed in recent days.

According to this data, there are four tankers waiting to load crude oil and fuel oil at the port of Paraguana and another eight waiting at the Jose port—PDVSA’s largest export terminal—to load refined oil products. There are also ten vessels waiting to unload refined products for the Venezuelan market, but payments to the sellers have been delayed, and now so is unloading.

Venezuela has been struggling to rein in the decline of its crude oil production resulting from underinvestment, mismanagement, and, most recently, U.S. sanctions. In October, crude oil production fell to the lowest in nearly 30 years, as PDVSA is unable to pay for services rendered by oilfield service providers, who are now refusing to continue working with it.

To add insult to injury, the country’s largest refinery, Paraguana, suffered damages from a fire earlier this month, which caused a severe drop in capacity utilization to just 13 percent. The refinery has a daily capacity of 955,000 barrels of crude. Related: Are NatGas Prices About To Explode?

Venezuela’s fuel oil production also declined as a result of the outages following the fire and a drop in the input of medium and light crude in the distillation units where the oil product is made.

Over the last four years, crude oil production in Venezuela has fallen by about a million bpd, and in October the daily average was below 2 million bpd. Exports are also falling: in October, PDVSA exported 475,165 bpd to the United States, which was down 12 percent on September and 36 percent on October 2016. That’s the lowest daily export rate for the last 14 years.

By Irina Slav for

Tuesday, December 12, 2017

Unfazed by OPEC, Libya and Nigeria seek to boost oil output

Less than two weeks after OPEC’s decision to extend oil production cuts, Libya and Nigeria – the only two exempt members of the group – are signaling their intent to raise output next year.
FILE PHOTO: A man fixes a sign with OPEC's logo next to its headquarter's entrance before a meeting of OPEC oil ministers in Vienna, Austria, November 29, 2017. REUTERS/Heinz-Peter Bader
While several ministers at the Nov. 30 meeting of the Organization of the Petroleum Exporting Countries suggested the two nations had joined the output-curbing deal, both are working to add to their peak production from this year. 

On Friday, oil company Total said its new Egina field offshore Nigeria was on track to start next year – adding 10 percent to the country’s production. 

The field will have a capacity of 200,000 barrels per day (bpd) and launch in the fourth quarter of 2018, counterbalancing production constrained by aging pipelines, perpetual theft and sabotage. 

“That could certainly change the dynamics,” said Ehsan Ul-Haq, head of crude and products at Resource Economist, a consultancy. 

The Nigerian petroleum ministry did not respond to a request for comment on the Egina field startup, and whether production elsewhere would be curtailed as a result. 

On Saturday, the head of Libya’s U.N.-backed government met the head of Libya’s National Oil Corp (NOC) and the governor of Tripoli’s central bank to discuss how the corporation could get more cash to raise oil output next year. 

The NOC received a quarter of its requested budget in 2017, hampering efforts to sustain oil output near 1 million bpd. 

Any additional funds could help make crucial repairs to the country’s energy infrastructure, a regular target for militant attacks, and boost output above the roughly 1 million bpd mark where it currently stands. 

Libya’s NOC has so far not spoken officially about the OPEC deal and declined a Reuters request for comment.


The developments may come as a surprise to market observers, who, after the Nov. 30 meeting, believed Nigeria and Libya had agreed to participate in the OPEC agreement by imposing official caps at their peak 2017 production levels. 

Instead, the two countries merely provided their production outlook for 2018 and an assessment that the combined total would not exceed 2.8 million bpd, their forecast output for 2017, two sources familiar with the matter told Reuters. 

That outlook was dependent on both countries’ finances and security situation, one of those sources said. 

The headline of a statement issued by Nigeria’s petroleum ministry on the day of the OPEC meeting stressed, in block capitals, that Nigeria and Libya were exempt from cuts. 

Oil Minister Emmanuel Ibe Kachikwu emphasized in the statement that the nation’s condensates - a form of ultra-light crude - were exempt from any total, giving it leeway in calculations. He also told local media there was “no obligation” to do anything. 

Oil production from the two countries has averaged 1.7 million bpd and 900,000 bpd, respectively, this year according to Reuters assessments. 

But it has swung in each country in a range of 340,000-350,000 bpd.
Editing by Dale Hudson

Monday, December 11, 2017

China’s Sinopec Looking to Sell Nigeria Business

China’s Sinopec Group has hired BNP Paribas to sell its oil business in Nigeria and Gabon, three people with knowledge of the matter said, as the state-owned oil giant pares back its presence in Africa.

Sinopec and other oil groups including China National Petroleum Corp and CNOOC made large acquisitions between 2009 and 2013 with the help of low-cost loans from Chinese state-owned banks.
The hunt for overseas assets was intended to bulk up their energy reserves and meet future demand from China, the world’s second-largest economy.

But oil prices fell to about $27 a barrel in 2016 from more than $100 in 2014, making some of these investments unprofitable.

Benchmark Brent Crude oil is now trading at more than $60. Militants have also recently attacked oil and gas facilities in Nigeria, further discouraging Sinopec.

China’s economy, which was growing strongly when the company expanded, has also slowed. “Sinopec is trying to sever ties,” one of the people told Reuters.”It has hired BNP to sell (its) assets in Nigeria and Gabon.

A Sinopec spokesman did not respond to requests for comment and a BNP Paribas spokeswoman declined to comment.

Sinopec spent $7.24bn in 2009 for Switzerland-based Addax Petroleum, its largest ever foreign oil acquisition, to secure land in Nigeria, Gabon, Cameroon and Iraq that was licensed for extraction and exploration.

It offered considerable potential as commodity prices rose but bankers expect the Nigeria and Gabon assets to sell for less than $1bn. The sources said Sinopec was planning to sell Addax’s onshore and offshore oil and gas production sites in Nigeria and Gabon.

Sinopec’s Cameroon operation would be its only remaining project in Africa.

We’ve already seen several Chinese companies divest some of their overseas assets,” said a second person, who asked not to be named.”At the current oil prices, such investments (are not) economically viable for Chinese companies.”

The sources said Sinopec had also decided to sell Addax after a recent bribery investigation by Geneva prosecutors into payments made in Nigeria.

Addax agreed to pay 31mn Swiss francs to settle the bribery charges, for which its executive officer and legal director had also been charged, and shut its offices in Geneva, Houston and Aberdeen.

At the time, Addax said its parent company was closing the offices in response to low oil prices and did not comment on the investigations at the time. The Sinopec spokeswoman did not respond for a request for a comment on whether this was a reason for the sale.

Nigeria, Africa’s largest economy, fell into recession for the first time in 25 years in the second quarter of 2016, after militant groups attacked oil and gas facilities in its Delta region. That cut the country’s oil production dramatically.

Lower crude exports, Nigeria’s mainstay, meant less money in government coffers, especially the US dollars Nigeria needs to import essential products and keep businesses running.

The latest group of militants to emerge in the Delta earlier this year also threatened that oil facilities belonging to major international oil companies would be destroyed.

Sinopec’s assets in Nigeria and Gabon could attract the interest of companies already operating in the region including Perenco, which bought Total’s assets in Gabon for $350mn earlier this year, and Kosmos Energy, the sources said.

One of the people who spoke to Reuters said that Sinopec was looking to sell some of the Chinese company’s other exploration and drilling businesses outside China because of falling oil prices and regional political instability.

Sinopec has also agreed to sell its oil business in Argentina for $500mn to $600mn to Mexican company Vista Oil & Gas, according to sources, in part because of social unrest there.

Friday, December 8, 2017

Venezuela re-visited

Leading shipbroker Gibson has once again highlighted the plight of Venezuela, by saying that the focus had now shifted to its huge $150 bill foreign debt. 
Around three weeks ago, Venezuela missed a deadline to make $200 mill interest payments on two government bonds, resulting in Standard & Poor’s formally declaring the first default.
About the same time, the Venezuelan president stated the country’s intention to restructure its foreign debt and the Russian Finance Ministry announced that the two countries had signed a debt restructuring deal, allowing Caracas to make “minimal” payments to Moscow over the next six years to help it meet its obligations to other creditors.
Politics and geopolitics aside, the economic challenges faced by Venezuela have direct implications on the domestic oil sector. The country’s crude production has been in steady decline over the past couple of years, largely due to the lack of investment, the shortage of available funds and ill-maintained production infrastructure.
According to IEA data, crude output averaged just over 1.9 mill barrels per day in October, 2017, down by 0.55 mill barrels per day, or 22%, compared to October, 2015.
The decline in production has had negative implications for the country’s crude exports, although not to the same extent. Venezuela’s financial problems also hit its refining sector, where lack of maintenance has led to a notable decline in domestic throughput volumes, reducing the downward pressure on crude exports.  
Venezuelan crude trade to the US was one of the biggest consequences of the country’s economic and political problems. Between January and August of this year, crude shipments to the US averaged 0.69 mill barrels per day, down 175,000 barrles per day compared to the same period in 2015.
In addition, the EIA weekly estimates suggest that this trade has declined further in recent months, averaging just 0.5 mill barrels per day since early September. Interestingly, Venezuelan crude exports to China have increased. During the first eight months of this year, shipments to China averaged 0.44 mill barrels per day, up by 100,000 barrels per day, compared to the same period in 2015, Gibson said. .
Apart from direct trade implications, it was also reported by Reuters that PDVSA is increasingly delivering poor quality crude to its international customers, which has resulted in complaints, cancelled orders and demands for discounts. There are also reports of logistical issues and disputes over payments. For tonnage calling at Venezuelan ports, this translates into additional, and at times extended, delays and sporadic cancellations.
Despite their recent firming, oil prices are still below the level needed by Venezuela to balance its financial requirements. As such, the difficulties faced by the country at present are unlikely to disappear anytime soon.
The recent debt restructuring with Russia will help to ease the most immediate pressures but it is unlikely to be sufficient to reverse the slide in domestic crude production and exports, Gibson concluded.

Thursday, December 7, 2017

Goldman raises 2018 oil price forecast on robust OPEC commitment
  • Goldman lifted its Brent price forecast for next year to $62 a barrel and its WTI projection to $57.50 a barrel
  • "Of course, risks remain and we see these as skewed to the upside into 2018 on the risk of an over tightening, either because of new disruptions, demand exceeding our optimistic forecast of OPEC letting the stock draw run hot," Goldman analysts said
A stronger than anticipated OPEC-led commitment to extend production cuts will support prices through 2018, according to analysts at Goldman Sachs.

In a research note published late Monday, Goldman lifted its Brent price forecast for next year to $62 a barrel and its WTI projection to $57.50 a barrel. The revisions were up from $58 a barrel and $55 a barrel respectively.

While the OPEC-led deal "leaves room for an earlier exit than currently scheduled, we now reflect this resolve in our supply forecast, with full compliance for longer and a more modest exit rate," Goldman analysts said in the research note.

Oil prices have lost ground in the days following OPEC's deal with global producers last week. The 14-member cartel, Russia and nine other crude producers announced plans to extend their output cuts until the end of 2018.

The move was heavily telegraphed ahead of the decision, but oil producers had earlier indicated they could exit the deal if they feel the market was overheating.

'Risks remain' beyond 2018

"Of course, risks remain and we see these as skewed to the upside into 2018 on the risk of an over tightening, either because of new disruptions, demand exceeding our optimistic forecast of OPEC letting the stock draw run hot," Goldman analysts said.

However, Goldman said the response of shale oil and other producers to higher prices would likely incentivize OPEC and Russia to "pare back" their now greater capacity, thus leaving risks to prices skewed towards the downside over the long term.

The price of oil collapsed from near $120 a barrel in June 2014 due to weak demand, a strong dollar and booming U.S. shale production. OPEC's reluctance to cut output was also seen as a key reason behind the fall. But, the oil cartel soon moved to curb production — along with other oil-producing nations — in late 2016.

Brent crude traded at around $62.36 on Tuesday morning, down 0.14 percent, while U.S. crude was trading at $57.29, down 0.31 percent.

Sam MeredithDigital Reporter,

Wednesday, December 6, 2017

Oil falls as U.S. fuel stock build signals easing demand

Oil fell 2 percent on Wednesday after a sharp rise in U.S. inventories of refined fuel suggested demand may be flagging, while U.S. crude production hit another weekly record.
A worker prepares to label barrels of lubricant oil at the state oil company Pertamina's lubricant production facility in Cilacap, Central Java, Indonesia November 6, 2017 in this photo taken by Antara Foto. Picture taken November 6, 2017. Antara Foto/Rosa Panggabean/ via REUTERS 
Government data showed that U.S. crude stocks fell 5.6 million barrels, more than expected, though that was partially the result of the closure of the Keystone pipeline after a leak in South Dakota in mid-November, which cut flows to Cushing, Oklahoma. That line reopened Tuesday. 

However, gasoline stocks rose by 6.8 million barrels and distillate inventories were up 1.7 million barrels, both exceeding expectations in a Reuters poll. 

That hit prices of both crude and products in a market which is already heavily tilted bullish and thus potentially vulnerable to a selloff, analysts said. 

Gasoline stocks tend to build in December, but at 221 million barrels of inventory, stocks are slightly above the five-year average for this time of year. 

U.S. crude production rose to 9.7 million barrels per day, another weekly record, though short of all-time records reached in the 1970s. That increase may undermine efforts by global producers to cut supply. 

Supply cuts by the Organization of the Petroleum Exporting Countries, Russia and other producers that were extended at a meeting last week for the whole of 2018 have helped lift Brent prices by more than 40 percent since June. 

Prices have slipped from November’s peak, which represented two-year highs. 

“The sentiment-driven support to crude oil prices has somewhat dissipated as market participants look beyond last week’s OPEC meeting,” said Abhishek Kumar, senior energy analyst at Interfax Energy’s Global Gas Analytics in London. 

Brent crude futures LCOc1 were down $1.23, or 2 percent, at $61.63 a barrel by 11:21 a.m. EST (1621 GMT), after reaching a session high of $62.93, while U.S. crude futures CLc1 dropped $1.29, or 2.3 percent, to $56.33. 

Russian Oil Minister Alexander Novak said it was too early to talk about exiting the OPEC agreement, and that the process would be gradual. Analysts such as Goldman Sachs have said that the expected rise in demand in 2018 would mostly be offset by U.S. and Canadian supply growth. 

U.S. oil production C-OUT-T-EIA has climbed by 15 percent since mid-2016 to 9.7 million bpd, close to levels of top producers Russia and Saudi Arabia. 

“With U.S. production, we’re still in the throes of seeing that go ever higher. There’s only going to be more production coming which is very problematic for OPEC non-OPEC deal adherence,” said John Kilduff, partner at Again Capital in New York. 

Additional reporting by Scott DiSavino and Julia Simon in New York; Henning Gloystein and Keith Wallis in Singapore; Editing by David Evans and Marguerita Choy

Monday, December 4, 2017

Southern California oil refineries ordered to monitor, publicize neighborhood air quality

Southern California oil refineries ordered to monitor, publicize neighborhood air quality 
The air monitoring rules come as a series of fires, explosions, flaring incidents and other emergencies has sent smoke, dust and other pollutants into neighborhoods in recent years. Above, PBF Energy's Torrance Refining Co. (Luis Sinco / Los Angeles Times)

Oil refineries must install air quality monitors at their fence lines and pay for pollution monitoring systems in surrounding communities by 2020 under rules adopted by Southern California regulators.

The measures approved Friday by the South Coast Air Quality Management District board will provide the public with real-time information on refinery emissions, but do not include requirements that facilities reduce pollution when high levels are found.

The rules come as a series of fires, explosions, flaring episodes and other incidents has sent smoke, dust and other pollutants into the air in recent years, stirring community anxiety about the dangers of living near California refineries.

The region's eight major oil refineries in Carson, El Segundo, Paramount, Torrance and Wilmington will be required to make the pollution readings they collect available on a website.

The monitors — likely to include optical remote sensing devices and other new technologies — will measure 15 refinery pollutants, including smog-forming gases and toxic compounds like benzene, toluene and hydrogen cyanide. Regulators said the devices will provide data on routine emissions and accidental releases and also could help find and address leaks that might be going undetected.

Air district officials said the rules were drafted concurrently with legislation Gov. Jerry Brown signed in October that requires air monitors to be deployed at refinery fence lines and in nearby communities by 2020.

The measures earned praise from community groups, environmentalists and local officials who have long sought more information on what people near the sprawling facilities were breathing.

"Refinery emissions affect our communities at all times, especially our children," said Maria Ramos, a member of Communities for a Better Environment who lives near a refinery in Wilmington. "But we are not aware of the levels of emissions that are being spewed into the air or what chemicals we're being exposed to."

Mayor Albert Robles of Carson, home to two refineries, welcomed the monitoring but criticized the rule because it "does not provide a mechanism to address the health risks once the monitoring data is gathered and known" and "makes no requirements for the refineries to take action to control these emissions."

The Western States Petroleum Assn. supports the monitoring rules, Southern California region director Patty Senecal said.

The community monitoring network, paid for by fees charged to refineries, could include traditional fixed stations as well as remote sensors distributed throughout neighborhoods, officials said. The air district will consider suggestions from the public as it decides where to deploy those monitors.

The rules will phase in over the next two years, along with an array of other refinery monitoring standards being rolled out by state and federal officials. Those include U.S. Environmental Protection Agency rules requiring fence-line monitoring for benzene and other mandates under recent legislation that extended the state's cap-and-trade program for greenhouse gases.

Bay Area pollution regulators adopted similar requirements for fence-line monitoring at oil refineries last year.

Friday, December 1, 2017

Magellan Midstream Launches Open Season for Proposed Crude Oil Pipeline from the Permian and Eagle Ford Basins to Corpus Christi and Houston

TULSA, Okla., Dec. 1, 2017 /PRNewswire/ -- Magellan Midstream Partners, L.P. (NYSE: MMP) announced today that it intends to develop a new pipeline and has launched an open season to assess customer interest to transport various grades of crude oil and condensate from the Permian and Eagle Ford Basins to multiple destinations in the Corpus Christi and Houston, Texas markets, including Magellan's existing crude oil terminals in these markets. All potential customers must submit binding commitments by 5:00 p.m. Central Time on Feb. 1, 2018.

The proposed project would include construction of an approximately 375-mile, 24-inch diameter pipeline from Crane to a location near Three Rivers, Texas, providing shippers the option to ultimately deliver crude oil and condensate from the Three Rivers area to the Houston area via a new 200-mile pipeline or to the Corpus Christi area via a new 70-mile pipeline. The potential pipeline system is expected to have an initial capacity of at least 350,000 barrels per day (bpd) with the ability to expand up to 600,000 bpd for each destination, if warranted by industry demand.

Additional pipeline extensions are being considered for Midland and Orla, Texas in the Permian Basin and Gardendale and Helena, Texas in the Eagle Ford Basin. Magellan previously announced the construction of a 60-mile, 24-inch Delaware Basin pipeline to deliver crude oil and condensate from Wink to Crane.

Subject to receipt of all necessary permits and approvals, the proposed pipeline could be operational by the end of 2019.

For customer inquiries about the open season, please contact Brant Easterling at (918) 574-7665 or More information about the open season is available at

About Magellan Midstream Partners, L.P. 

Magellan Midstream Partners, L.P. (NYSE: MMP) is a publicly traded partnership that primarily transports, stores and distributes refined petroleum products and crude oil. The partnership owns the longest refined petroleum products pipeline system in the country, with access to nearly 50% of the nation's refining capacity, and can store approximately 100 million barrels of petroleum products such as gasoline, diesel fuel and crude oil. More information is available at
Portions of this document constitute forward-looking statements as defined by federal law. Although management of Magellan Midstream Partners, L.P. believes such statements are based on reasonable assumptions, actual outcomes may be materially different. Among the key risk factors that may have a direct impact on the opportunity described in this news release are: (1) the ability to negotiate and sign definitive agreements with potential customers; (2) the ability to obtain all required rights-of-way, permits and other governmental approvals on a timely basis; (3) price fluctuations and overall demand for crude oil and condensate; (4) changes in the partnership's tariff rates or other terms imposed by state or federal regulatory agencies; (5) the occurrence of an operational hazard or unforeseen interruption; (6) disruption in the debt and equity markets that negatively impacts the partnership's ability to finance its capital spending and (7) willingness to incur or failure of customers or vendors to meet or continue contractual obligations related to this potential pipeline. Additional information about issues that could lead to material changes in performance is contained in the partnership's filings with the Securities and Exchange Commission, including the partnership's Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent reports on Forms 8-K and 10-Q. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, especially under the heading "Risk Factors." Forward-looking statements made by the partnership in this release are based only on information currently known, and the partnership undertakes no obligation to revise its forward-looking statements to reflect events or circumstances learned of or occurring after today's date.


Paula Farrell 
Bruce Heine

(918) 574-7650 
(918) 574-7010