Crude oil imports by China's independent refineries in eastern Shandong province, Xinhai Petrochemical in Hebei and Fengli Petrochemical in Henan rebounded 11% month on month to around 7.435 million mt in October, or 1.76 million b/d, according to a monthly survey by S&P Global Platts.

October imports rose from an 11-month low of 6.69 million mt in September as independent refineries were trying to use up their crude quota allocations by end October in order to secure a full allocation of quotas for 2018.

At end October, the remaining import quota volume for November and December stood at around 20.2 million mt, most of it held by the refineries that had received fresh quota allocations in recent months.

In October, 21 independent refineries -- 19 in Shandong, Xinhai and Fengli -- received a total 6.19 million mt of imported crude, Platts data showed. Some of this volume could be resold to other refineries, including non-quota holders, market sources said.

The balance of the import volume in the month was received by trading companies Vitol, BP, Trafigura, Mercuria, Gaida, Huayue, Taifeng Hairun and PetroChina's trading arms that supply to independent refineries.

The total for October crude imports included parcels that arrived at ports in Shandong and Tianjin and completed discharge operations in the month, as well as cargoes that arrived in late September and finished offloading in early October.

TOP BUYERS

After a drop in September, ChemChina overtook Dongming to be the biggest buyer among the independent refineries in October, taking 1.28 million mt of crudes, up 108% from September.

The company received around 715,000 mt of Russian ESPO blend, accounting for 56% of total imports, with the balance being 307,000 mt of Malaysia's Nemina crude, 130,000 mt of Djeno and 130,000 mt of Mondo.

Dongming was the second-biggest importer at around 686,000 mt of crude, up 3% month on month. The refinery received VLCCs of Merey crude and Oman crude, with the balance being Napo crude from Ecuador. It was the first import of Napo by an independent refinery; it is a heavy, sour crude, with a 19 API and 2% sulfur content.

Qingyuan rose to be the third biggest buyer in October, importing around 487,000 mt of crude, surging from 167,0000 mt in September.

The refinery in October imported around 90,000 mt of Malaysia's Panera crude, the first by an independent refinery.

PetroChina's trading arm sold one similar cargo last month, but it could not be immediately confirmed if it was the supplier to Qingyuan.

Market sources said the refinery was in a rush to utilize its crude quotas as production at its facility in Zibo has not been stable in recent weeks.

Some refineries in Zibo were running at lower rates during the second half of October in order to cut emissions during the 19th National Congress of the Communist Party of China. AVAILABLE QUOTAS AT 20 MIL MT FOR NOV, DEC

Over January-October, the 27 crude quota holders surveyed reported importing 60.3 million mt of crude, leaving 20.2 million mt, or 25% of the annual quota allocation, to be filled by year end, according to Platts calculations.

But most of those quotas are held by refineries that received quotas in the second half of the year, as those major regular importers were running low after aggressive imports in previous months.

Refineries holding fresh quotas will ramp up imports in the coming months in order to fully use up their quotas, with an eye on ensuring they received full allocations for next year. But it is unlikely overall crude imports will continue at the same pace for the last two months of the year.

For those that run on low quotas, buying Venezuelan Merey crude, Boscan crude and other light crudes from PetroChina Fuel Oil Company could be an option, as this would not require a refinery to use its own quota allocation.

Independent refineries can also choose to import fuel oil and bitumen blend in place of crude oil, as has been done by ChemChina.

In October, ChemChina imported about 83,000 mt of fuel oil, the only one to take fuel oil as feedstock.

In addition, about four cargoes of bitumen blend arrived in Shandong port last month, totaling around 392,000 mt. This was in line with the volume that arrived in August of around 410,000 mt.

"Demand for bitumen blend has increased a little bit due to low quota problems towards the end of the year," said a trader source in Shandong. But only a few refineries are willing to crack the grade as it is not the ideal feedstock for most refineries, sources said.

Domestic offshore crude will also be an alternative for those refineries with low quotas.

CRUDE IMPORTS IN NOV TO DROP

Crude imports in November are expected to slide from October as quotas will be a big issue for most independent refineries, according to market sources.

"The imports are likely to slow down as only those new quotas holders have sufficient quotas on hand," said a trader in Shandong.

But those quota holders are reluctant to sell their quotas, even though the fee of quota transactions has recently been raised to around Yuan 200 ($29)/mt from around Yuan 180/mt.

"Still no one is willing to sell, and few quota deals are made as all refineries would like to keep it for themselves," the trader said.

Due to the lack of quotas, trading companies have to slow their imports in November and December, which would contribute to a drop in overall imports.

Major independent refineries, on the other hand, will generally maintain their import pace according to their production schedules.

https://www.platts.com/latest-news/oil/singapore/china-data-independent-refiners-oct-crude-imports-27884764

New York’s State Energy Plan, self-proclaimed to include some of the nation’s most ambitious 2030 clean energy targets, has perhaps by necessity intensified the discussion of carbon prices in the wholesale power markets, possibly redefining their traditional role.

The Brattle Group on August 11 released a study on behalf of the New York Independent System Operator to evaluate how pricing carbon emissions could complement existing state climate goals.

The report analyzed the impacts of a $40/ton carbon charge in 2025, less than the expected $17/ton Regional Greenhouse Gas Initiative price,  which is consistent with the “social cost of carbon” already adopted by the New York Public Service Commission in its Clean Energy Standard Order.

In this blog, we go deeper into the details of the Brattle report, with additional insight from its lead author, Sam Newell.

In an event organized by NYISO and the New York State Department of Public Service in Albany, New York, in September, Newell discussed the report with stakeholders and market participants.

In discussing the approaches to implementing a carbon price, Newell said, “We’ve been talking about this stuff for years; this is not new. What is new is the idea to actually do it.”

True, New York is already participating in RGGI, but Newell said that RGGI prices are not reflective of the social cost of carbon.

“RGGI to me doesn’t feel designed as sort of the driver of decarbonization; it more is tracking the many states’ agreed upon goals. … It’s not going to give you the same price that we’re talking about in this context, corresponding to the social cost of carbon,” Newell said.

The proposed $40/ton carbon charge would, on average, increase wholesale energy prices paid by customers by $18.8/MWh (ranging from $16.70 to $20.10/MWh across zones), according to the report. These charges would be collected from fossil generation and imports.

Estimated customer cost impact of $40/ton carbon charge in 2025 ($/MWh)

Static analysisNYCA average

I. Increase in Wholesale Energy Prices18.8

II. CO2 Revenue – (A) Allocate by Load Share-9.4

II. CO2 Revenue – (B) Allocate to Equalize Zonal Impact-9.4

III. Lower ZEC Prices-1.0

IV. Lower REC Prices-2.0

V. Increased TCC Value-0.3

Subtotal (A)6.0

Subtotal (B)6.0

Dynamic Analysis

VI. Adjustments to Static Analysis due to Entry of CCs-3.5

VII. Carbon Price-Induced Abatement-0.8

Total Net Change in Customer Costs (A)1.7

Total Net Change in Customer Costs (B)1.7

Source: The Brattle Group

So is the carbon charge, as proposed, the same as a carbon tax?

“The idea of a carbon charge is somewhat similar to that, but the idea is that it is fairly simple and it does not involve any tax authority,” Newell said.

More importantly, NYISO would return to customers all carbon charges to help offset adding a carbon price to the market. The form that will take, however, still remains an open discussion.

With a carbon price in place, Newell addressed the four ways a carbon charge could reduce emissions. Newell said during the meeting that this is the most uncertain part of the analysis as there are a number of assumptions.

“What we tried to do is give reasonable assumptions to give an indicator of what plausibly might the effects be,” Newell said.

The first impact of a carbon charge is the tilting of investments in renewables, specifically 2,000 MW of new wind and solar projects, resulting in an annual carbon reduction of 1 million tons.

Second, peaker plants and old steam units would be displaced by the lowest-emitting technologies, reducing carbon emissions by 500,000 tons/ year, assuming 700 MW of combined-cycle generators enter the market.

Third, price signals would incentivize load shifts from the most emitting hours of the day to the least emitting hours. This is the smallest contributor to carbon reductions.

Lastly, carbon prices would incentivize energy efficiency and conservation, reducing emissions by more than 1 million tons annually. The largest customers would see higher costs. Overall costs would not rise substantially, however, given the carbon refund. However, the higher nominal price or an alternative carbon refund could induce more efficiency and conservation.

There are more moving pieces to this study, but we have focused on the core price assumptions and the key drivers in carbon reduction here.

The bottom line is that this is a highly complex issue that would add a substantially higher carbon tax than RGGI. It also remains to be seen in what form the carbon tax revenue will be returned to consumers.

http://blogs.platts.com/2017/11/03/carbon-pricing-new-york/

Spanish oil major Repsol posted close to a 90 percent jump in third-quarter adjusted net profit after higher oil prices boosted its production division while its refining arm remained highly profitable.

Repsol’s performance echoed that of European competitors Shell, Total and BP, which all reported stronger quarterly profit on the back of the recovery in crude prices.

Average recurring net profit adjusted for one-off gains and inventory effects (CCS net profit) came in at 576 million euros ($671 million) in the July-September period, compared with a 553 million euro consensus in a Reuters poll of analysts.

Third-quarter production reached 695,000 barrels per day (bpd), versus 671,000 bpd in the same period of 2016 while the refining margin was $7 a barrel, up from $5.10 a year ago.

Net debt fell to 6.97 billion euros at Sept. 30, from 7.48 billion euros three months earlier, and is on track for the year-end target of less than 7 billion euros.

http://www.reuters.com/article/repsol-results/update-1-repsol-profit-leaps-on-refining-and-crude-price-gains-idUSL8N1N91B2

The cost of taking 270,000 mt crude oil cargoes from Hound Point, UK, to the Far East on VLCCs rose $300,000 Wednesday to reach a nine-month high of $5.4 million lumpsum, the highest since January 20, according to S&P Global Platts data.

Glencore was heard to have paid $5.4 million for a Southwold-Far East voyage on November 15 on the Texas VLCC. A trader at Glencore declined to comment.

This was one of a steady flow of VLCC fixtures to take North Sea crude oil to the Far East in recent weeks which has trimmed the North Sea position list, and in some case left charterers in the region reliant on ballasters to do fresh liftings.

"There has been a big gap in fixing because there were no ships available for natural [loading] dates," a shipbroker said. "Charterers could only take ballasters from the East as and when they arrived, and they wanted high rates for those...the North Sea position list is still tight and there are only a couple of ships left until mid-December now."

While rising VLCC freight rates and seemingly tepid Asian demand would appear bearish for the arbitrage, a steady stream of ships have been fixed to take Forties and Ekofisk crude to the Far East in November.

In addition to the Texas fixture, trading and shipping sources have said the Houston, Ellinis and New Vista VLCCs are all set to transport Forties to the Far East in November.

Although North Sea arbitrage fixtures have continued unabated, some traders have questioned the current extent of Far Eastern demand, particularly given the large volume of crude which China and South Korea have purchased from a variety of regions in recent weeks.

"The oil will sail East but I still don't see many end-users for November Forties so this could all be a house of cards unless the Eastern demand really is there to take up the slack," a North Sea crude trader said.

https://www.platts.com/latest-news/shipping/london/hound-point-east-vlcc-rates-at-9-mo-high-on-tight-26832781

Iraqi Basra crude cargoes in November have sold at the widest discounts to official prices in more than a year, with cargoes backed up after hurricanes hit the U.S. Gulf coast facing competition from Mexican crude, trade sources said on Friday.

The drop in U.S. demand for Iraqi oil may impede the Organization of the Petroleum Exporting Countries' second-largest producer's effort to increase exports from the southern port of Basra to make up for a shortfall from the north.

Basra crude shipments have been backed up after four hurricanes disrupted arrivals into the U.S. Gulf between August and October.

More than 22 million barrels of Basra crude were due to land in the United States in both October and November, trade flow data on Thomson Reuters Eikon showed, the highest monthly volumes since data tracking started in 2015.

But some of the cargoes remain unsold as crude from Mexico has filled some U.S. demand, a Singapore-based trader said.

U.S. imports of Mexican crude hit a four-month high of 21.3 million barrels in October, data showed, after earthquakes and storm damage shut Mexico's biggest refinery for most of the month. "The hurricanes caused an overhang of Basra crude while more Mexican oil was sold into the U.S. because of the refinery turnaround," the trader said.

November-loading Basra Light discounts widened to 30 cents to 70 cents a barrel to OSPs. In the previous month the price ranged from a premium of 30 cents to a discount of 10 cents, depending on the cargo's destination. Premiums for November-loading Basra Heavy slipped to 10 cents to 50 cents to official prices, they said, from premiums of 80 cents to $1 the previous month. They declined to be named as they are not authorised to talk to the media.

To cope with Basra crude surplus in the United States, traders have slowed ships and stored some cargoes off the Gulf coast, shipping data on Eikon showed.

For example, supertanker New Achievement, carrying 2 million barrels of Basra crude, has been parked in the U.S. Gulf since Oct 8.

The big discounts for Basra are attracting demand from Asian refiners, the sources said. December-loading Basra crude for Asia has been sold at a discount of about 50 cents as Iraq is likely to raise monthly official prices in line with Saudi Arabia while also increasing exports. In a further blow to Iraq, it failed to attract any bids for prompt-loading Basra crude to Europe in an auction on Tuesday.

http://www.kitco.com/news/2017-11-03/Weak-U-S-demand-for-Basra-crude-wipes-out-premium-for-Iraq-apos-s-oil.html#.WfwlwRKZX4k.twitter

The move by OPEC and certain non-OPEC countries to reduce oil supply, by 1.8 MMb/d starting in January 2017, is making inroads in shrinking global oil stocks. However, a declaration of mission accomplished is premature—especially since the third quarter typically records a seasonal decline in stocks. IHS Markit balances suggest that OECD commercial oil stocks are unlikely to return to the five-year average until around the end of 2019. Therefore, the pressure will remain on OPEC to keep the production restraint in place for a far longer period than was originally planned in late 2016.

From the start of 2014 through to the storage peak in mid-2016, the oil supply glut and accompanying contango price structure—with future prices higher than near-term prices—fueled a global oil stock build of almost 1 billion barrels, including about 350 million barrels added to government-controlled strategic inventories. Since mid-2016, global oil stocks have declined slightly but still remain high.

At the November 2016 OPEC meeting, OPEC and some non-OPEC countries, in a historic decision, stepped back into a market balancer role, pledging to reduce their combined production by about 1.8 MMb/d. OPEC announced that the primary purpose of the supply cuts was to “accelerate the ongoing drawdown of the stock overhang.”

In mid-2017, on behalf of OPEC, the Saudi oil minister, Khalid A. Al-Falih, said, “Our joint declaration with Russia concluded that while the rebalancing goal is on its way to being achieved, more needed to be done to draw inventories towards the five-year average.”

To be sure, ultimately, OPEC and other producers want to bring about higher prices, and they have indicated that the OECD commercial/industry oil stock five-year average is the target. Commercial oil stocks have fallen by about 50 MMbbl in 2017 but remain 150–200 MMbbl above the five-year average.

Our expectation is that global oil inventories will resume growth in 2018, increasing by 100 MMbbl through 2018–19. However, most of these builds may be in strategic stocks and so some reduction in commercial oil stocks may still happen. Even so, getting commercial inventories down to the five-year average remains a significant challenge unlikely to be achieved in 2018.

This blog is a summary of a detailed report published on the IHS Markit Crude Oil Markets service.

http://blog.ihs.com/too-early-to-declare-victory-in-war-on-high-oil-stocks

Monaco-based LNG shipper GasLog reported a profit for the third quarter of 2017 as the contribution from its spot vessels improved.

The company’s net profit for the quarter was $5.3 million compared to a $29 million net loss in the corresponding quarter a year ago.

GasLog’s CEO, Paul Wogan said that the company hit record revenues during the quarter, reaching $131.2 million, compared to $120.7 million in the third quarter of 2016.

The increase was mainly driven by the new deliveries to its fleet, the GasLog Geneva and the GasLog Gibraltar, and increased revenues from vessels operating in the spot market in both periods.

Wogan noted that the LNG shipping market fundamentals are improving.

“The increase in LNG supply from both the United States and Australia is creating greater shipping activity, as the additional supply is being matched by rising demand, particularly in Asia and Europe,”he said.

The company further expects the re-emergence of significant gas price differentials between the U.S., Europe and Asia will stimulate more inter-basin trade and will result in longer average voyage distances, which is positive for LNG shipping.

In the short-term LNG shipping market, spot rates have been consistently higher in 2017 than in 2016 as an increasing number of fixtures have led to higher utilization, a return of round-trip economics and an increase in customers looking for multi-month charters.

Commenting on the Alexandroupolis LNG project in Greece, where DEPA has signed a cooperation agreement for its participation in the project, which is being developed by Gastrade, Wogan said that progress is being made.

GasLog has three newbuilds on order at Samsung Heavy Industries and two newbuilds on order at Hyundai Heavy Industries, all on schedule for delivery from the first quarter of 2018 through to the second quarter of 2019.

http://www.lngworldnews.com/gaslog-turns-to-profit-as-lng-shipping-market-improves/

The Nigerian militant group Niger Delta Avengers said on Friday that they had ended their ceasefire in the oil-rich southeasterly region.

Attacks on oil facilities in the Niger Delta in 2016 cut Nigeria’s oil production from a peak of 2.2 million barrels per day to near 1 million barrels per day, the lowest level seen in Africa’s top oil producer in at least 30 years.

The OPEC member relies on crude oil sales for two-thirds of government revenue and most of its foreign exchange. Attacks in the Delta helped to push Africa’s largest economy into recession in 2016. It emerged in the second quarter of this year, mostly due to increased oil production.

"Niger Delta Avenger's ceasefire on Operation Red Economy is officially over," stated the heading of a post on the group's website ( www.nigerdeltaavengers.org/ ). The militants want a larger share of Nigeria's oil wealth to go to the impoverished southern swampland region.

“We can assure you that every oil installation in our region will feel the warmth of the wrath of the Niger Delta Avengers,” the group said.

The Niger Delta Avengers, who were responsible for most of last year’s attacks, announced an end to hostilities in August 2016. There have been no substantial attacks by any groups in the region since January.

http://www.reuters.com/article/nigeria-oil/update-1-niger-delta-avengers-group-says-it-ends-ceasefire-in-oil-region-website-idUSL8N1N93Q8

U.S. shale player Sanchez Energy said that it expects to cut spending next year, after reporting a record-setting rate of production in the third quarter.

"As 2017 draws to a close, we expect capital spending to be between $525 million and $550 million for the full year," CEO Tony Sanchez III said in a statement. "We anticipate that 2018 capital spending will be $75 million to $100 million less than 2017."

Sanchez is one of the larger operators in the Eagle Ford shale basin in Texas and added more than 300,000 acres to its portfolio through a March acquisition from rival shale player Anadarko Petroleum. The company said third quarter production increased 43 percent over the same period last year and reached a record rate of around 80,000 barrels of oil equivalent in the early part of the fourth quarter in part because of increased activity in the Eagle Ford shale.

The Eagle Ford shale basin was in the path of Hurricane Harvey, which swept over most of Texas in early September. The company said it suspended some operations because of the storm, but production was relatively spared. In an update on operations after Harvey dissipated, Sanchez said production was around 75,000 barrels of oil per day, in line with its expectations for the third quarter.

Sanchez raised around $100 million in cash from the sale of non-core assets in the Eagle Ford in the third quarter. The company's average cost per barrel of oil and natural gas production, meanwhile, was up 29 percent from the same period last year.

Of the seven shale basins monitored by the U.S. Energy Information Administration, the forecast for Eagle Ford oil production is the second lowest after Haynesville, which is largely a natural gas basin. The EIA said Eagle Ford production should be around 1.2 million barrels per day this month a gain of less than 1 percent from October. Production from the Permian shale, largely situated in Texas, is expected to increase by about 2 percent for a November average of 2.6 million barrels per day.

Sanchez spent all but 6 percent of its total capital expenditures in the third quarter on drilling-related activities.

https://www.upi.com/Energy-News/2017/11/03/Sanchez-Energy-trims-spending-plans-for-2018/3821509711404/?utm_source=sec&utm_campaign=sl&utm_medium=3

Chadian government officials will meet Glencore executives in Paris on Monday to discuss restructuring the country’s debt, two senior Chadian government sources with knowledge of the matter told Reuters on Sunday.

Chad has been trying renegotiate its hefty external commercial debt to Glencore, which eats up nearly all of its oil profits - the country’s main source of revenue.

One of the sources said Glencore was open to the idea of rescheduling. A Chadian government spokesman and a Glencore spokesman did not immediately respond to requests for official comment.

Chad has been on a collision course with its top creditor, as it wants to divert oil from the Swiss trading house to U.S. energy company ExxonMobil from the new year amid the dispute over the debt restructuring.

Chad wants to hand over crude oil marketing rights currently held by Glencore under a $1.4 billion loan agreement to Exxon, the biggest oil producer in the central African country.

A sticking point has been a request from Chad for another grace period on principal repayment. The officials said this would be discussed on Monday.

Hit by drought, a refugee crisis and a costly military campaign against Islamist militant group Boko Haram, Chad has had loans from the IMF, World Bank and African Development Bank, with another $12.9 billion of pledged funding as of September from public and private donors for a 2017-2021 development plan.

http://www.reuters.com/article/us-glencore-chad-oil/chad-and-glencore-to-meet-in-paris-on-monday-to-discuss-debt-government-sources-idUSKBN1D515N

China National Petroleum Corp (CNPC) plans to reduce natural gas supplies to industrial users as it expects supply shortages this winter after millions of residential households were switched to gas for heating under a government program to reduce pollution.

CNPC, one of China’s top three gas producers, said it will cut supplies to industrial clients by a range of 3 percent to 10 percent, the state-run China Youth Daily reported on Monday citing several unidentified sources. The article was also posted on CNPC’s main website.

The company expects a 12 percent jump in gas consumption from a year ago because of the residential switch.

CNPC will boost purchases of spot liquefied natural gas (LNG) cargoes and further lift the capacity of LNG receiving terminals, China Youth Daily reported. The company will also try to increase imports from Central Asian countries such as Kazakhstan.

The oil and gas producer said it can only provide about 76.5 billion cubic meters (bcm) of gas even if it runs its gas fields and LNG terminals at full capacity and fully stocks its underground storage, lower than the current demand of 81.3 bcm.

CNPC is the first natural gas product to reduce supplies as China could be dealing with a supply crisis after the central government has pushed more residents to use gas heating rather than coal heating. Under the new rules, residential users will have priority over industrial users in case there are supply curtailments.

China’s government moved the residential user onto gas to combat smog that typically develops from coal emissions in the winter as more coal is consumed to heat homes and run power plants.

The company has a working volume of 7.4 bcm at its natural gas storage sites, accounting for 5 percent of its annual sales plan, the newspaper reported.

http://www.reuters.com/article/us-china-natural-gas-supplies/cnpc-plans-to-cut-gas-supplies-to-industrial-users-state-media-idUSKBN1D608S

Mexico’s national oil company Pemex has made its biggest onshore oil discovery in 15 years with a find in the eastern state of Veracruz, President Enrique Pena Nieto said on Friday.

Pena Nieto said Pemex made the discovery by drilling its onshore Ixachi well, near the municipality of Cosamaloapan, and that the overall field is believed to hold some 350 million barrels of proven, probable and possible reserves.

Pena Nieto, who pushed through Congress a sweeping energy reform in 2013 that ended Pemex’ decades-long monopoly, made the announcement at the company’s Tula refinery.

He was flanked by his energy minister, Pemex’ chief executive and a range of other government and union officials. While crude export revenue once contributed as much as 40 percent of government revenue, that figure has dropped to under 20 percent as oil prices have slumped in recent years.

The announcement confirmed a Reuters story from earlier on Friday. The onshore field’s original volume in place is estimated at 1.5 billion barrels of oil equivalent.

The light oil field should begin producing by the end of 2018 or the beginning of 2019, Pemex CEO Jose Antonio Gonzalez Anaya said in a phone interview.

The area near the discovery is located where infrastructure already exists which should allow for quicker development, Pemex said in a statement following the announcement, adding that the find could double in size.

Gonzalez Anaya said the company has not decided whether it will develop the discovery by itself or with an equity partner, and he added that it is too soon to provide a production forecast or a spending plan for the field.

“We’re just now announcing the field’s discovery, and we still need to delimit it as well as establish a development plan,” said Gonzalez Anaya.

The discovery is similar in size to the field associated with the Zama well announced in July by Britain’s Premier Oil, along with partners, U.S.-based Talos Energy and Mexico’s Sierra Oil and Gas, the company said.

The energy reform championed by Pena Nieto was designed to reverse a decade-long crude production slump by attracting billions of dollars in investment via new foreign and private producers.

Mexico hit peak oil output in 2014 with about 3.4 million barrels per day (bpd).

Pemex, still responsible for nearly all of Mexico’s current crude production, expects to end 2018 with average output of 1.9 million bpd.

http://www.reuters.com/article/us-mexico-pemex/pemex-makes-mexicos-biggest-onshore-oil-find-in-15-years-idUSKBN1D32FK

U.S. shale producers are telling investors impatient for better returns that they can keep boosting oil output aggressively and do so while still making money for shareholders.

Investors have pushed top U.S. shale companies to focus on returns, rather than higher output, a move that threatened to slow the breakneck growth in supply sparked by the shale revolution in the world’s top oil consumer.

For the Organization of the Petroleum Exporting Countries, slower shale production gains would have been welcome. The cartel this year put caps on its members’ production to end a supply glut and boost oil prices, only to find U.S. shale gains and record exports muting the impact of their curbs.

But in comments during recent third-quarter earnings calls, shale executives signaled they expect to deliver both higher returns and output.

At least seven of the largest U.S. shale companies, including Noble Energy Inc (NBL.N) and Devon Energy Corp (DVN.N), forecast 10 percent or better production gains this quarter in the Permian Basin of West Texas and New Mexico, the largest U.S. oilfield.

Underpinning the effort: Rising global oil demand and crude CLc1 prices that are up about 30 percent since June lows. Shale producers are also proving they can drive output higher even after several last summer reported some Permian wells had begun delivering more natural gas, a sign of aging fields.

“I’d like to think the industry is changing for the better,” said Todd Heltman of wealth manager Neuberger Berman, which invests in shale producers. “Investors are more focused on return metrics.”

Devon plans to boost oil production this quarter by 20 percent from the Permian and Oklahoma shale plays and spend less on each new well.

“We are taking the appropriate steps to become an industry leader with our disciplined approach to capital allocation,” said Devon Chief Executive Dave Hager.

U.S. shale output is expected to hit 6.1 million barrels of oil per day (bpd) this month, up 35 percent from a year earlier, according to the U.S. Energy Information Administration.

The inventory of drilled-but-uncompleted wells, a backlog for future output, in September reached 7,120, up 42.6 percent from the year-ago period, and an all-time high. While the number of oil drilling rigs in the United States has slid in recent months, each rig’s efficiency has jumped sharply in the past year.

EOG Resources Inc (EOG.N) boosted third-quarter production by 8 percent and swung to a $100 million profit, from a loss in the same period last year, helped in part by rising oil prices. CEO Bill Thomas said the company is aiming for 20 percent increase in U.S. crude output this year over last. Its stock is up nearly 17 percent since August.

Noble Energy forecast its fourth-quarter shale production will rise 15 percent to at least 102,000 bpd.

“If you look at the growth from our Permian Basin drilling operations, you can see very substantial increases in oil production growth of about 15 percent,” said Tim Dove, CEO of Pioneer Natural Resources Co (PXD.N).

Pioneer, one of the largest Permian oil producers, plans to boost its shale output by at least 16,000 bpd this quarter. The company’s shares are up 15.4 percent since early August.

Next year could bring more of the same gains.

“We are excited about the trajectory of production growth in the upcoming quarters,” said Vicki Hollub, CEO of Occidental Petroleum Corp (OXY.N), another top Permian producer. Oxy projects its Texas oil output will rise by more than 80,000 bpd by the end of 2018, to more than 200,000 bpd.

Shale producers outside Texas are cranking up production, too.

Whiting Petroleum Corp (WLL.N), which operates in North Dakota’s Bakken shale, plans a 10 percent jump in its fourth-quarter production.

“We’re confident about the areas in which we’re drilling through to the end of the year and really, through the end of 2018,” said Jim Volker, who retired as Whiting’s CEO this week.

Continental Resources Inc (CLR.N) and Parsley Energy Inc (PE.N), two other large U.S. shale producers, are due to report quarterly results next week.

OPEC TENSION

U.S. shale increases are keenly watched by OPEC, and likely will be in the spotlight when the group and other major producers meet on Nov. 30 in Vienna.

Emmanuel Kachikwu, Nigeria’s oil minister, warned at the last OPEC meeting in May that the group would “sit down again and look at what process it is we need to do” if U.S. shale output continues to weigh on global markets.

Adding to the pressures, major oil companies that were late to recognize shale’s potential have brought their own resources to bear. Chevron Corp (CVX.N) and Exxon Mobil Corp (XOM.N)are setting out aggressive plans for U.S. shale production, especially in the Permian.

Exxon, which more than doubled its Permian holdings earlier this year, plans to boost the number of drilling rigs there by 50 percent, to 30, by the end of next year. By 2020, Exxon expects its Permian oil production to rise 45 percent.

Chevron, which has operated in the Permian since the 1930s, recently added a 15th drilling rig in the Permian, with plans to add five more.

“We’ll be in a position to grow production for a period of years just from the shale,” Chevron CEO John Watson said of the company’s Permian operations.

http://www.reuters.com/article/us-shale-output/u-s-shale-producers-promise-both-higher-output-and-returns-idUSKBN1D401F

Baker Hughes on Friday reported that the number of active U.S. rigs drilling for oil fell by 8 to 729 this week. The figure had climbed by just 1 rig last week after three-consecutive weeks of declines. The total active U.S. rig count, which includes oil and natural-gas rigs, also declined by 11 to 898, according to Baker Hughes. 

https://www.marketwatch.com/story/baker-hughes-reports-a-sizable-decline-in-weekly-us-oil-rig-count-2017-11-03

David Rheinlander used to dream of building a cabin in the woods behind his house in southwestern Pennsylvania. Now when the 57-year-old looks across his backyard, he sees a line of cut trees, piles of dirt, and stacks of steel pipe where he once envisioned a tiny cabin. For the past six months, construction crews carved their way through the back of his property. The roughly 100-foot-wide path they’re cutting through the rolling hills extends about 700 miles to the west, running through neighboring Ohio and all the way up into Michigan.

The pathway is for a pipeline that will bring huge amounts of natural gas out of sparsely populated Appalachia and into big cities across the Midwest. The pipeline, called Rover, is being built by Energy Transfer Partners LP, of Dallas, which has spent three years and a total $4.2 billion on the painstaking process of winning permits, clearing miles of rugged terrain, and fighting a pitched legal battle against environmental groups and landowners.

Rover is scheduled to begin shipping as much as 3.25 billion cubic feet of natural gas a day in early 2018. When fed through a natural gas-fired power plant, that’s enough to power about 30 million homes. Rover is one of a handful of pipelines set to open next year that will begin moving natural gas from the massive Marcellus and Utica shale formations that lie beneath parts of Ohio, West Virginia, Pennsylvania, and New York.

Rheinlander isn’t exactly thrilled to have Rover in his backyard, but he supports efforts to build up the region’s economy. “I’ve got no issue with them developing gas,” he says, eyeing the pipeline pieces scattered atop the dirt. “My overall feeling is that we’ve got to develop as much energy in this country as we can.”

A relative latecomer to America’s shale revolution, the Marcellus and Utica regions arebooming. In the past 10 years, natural gas production there, driven by advances in horizontal drilling, has multiplied by a factor of 10, to about 25 billion cubic feet a day, or roughly a third of U.S. output. Despite the increase in production, the energy companies that drill the wells to produce the gas complain they’ve been bogged down by a thicket of political and regulatory hurdles, as well as opposition from environmentalists and some landowners. These obstacles have prevented the region’s energy industry from reaching its full potential, they argue.

Sometimes dubbed the Saudi Arabia of natural gas, the Marcellus is thought to hold a century’s worth of reserves. But after an initial boost of investment and optimism by drilling companies, activity started to stall, mostly because there weren’t enough pipelines to deliver the gas to large markets. Companies kept drilling wells but left many of them uncompleted, waiting for the day when pipelines would be finished. Now, with a slate of projects opening in 2018, the number of drilled but uncompleted wells in the Marcellus has fallen 28 percent since February 2014. With Donald Trump in the White House pushing to cut regulatory red tape to unleash America’s energy supply, a lot of companies have a sense of expectation. “The only thing holding back the Marcellus Shale is lack of energy infrastructure,” says Rob Thummel, managing partner at Tortoise Capital Advisors. “Natural gas production volumes have exceeded available pipeline capacity for several years.”

Fifty miles west of Rheinlander’s home, in eastern Ohio, Enbridge Inc.’s Nexus transmission line will soon begin its own 250-mile path up and around Lake Erie into Michigan. That project, scheduled to open around the middle of 2018, will be able to ship 1.5 billion cu. ft. of gas a day. And in northeast Pennsylvania, Williams Cos.’ Atlantic Sunrise project will soon be connecting that region’s gas producers to the Transco pipeline, a gas superhighway that runs from the Gulf of Mexico up the East Coast to New York City. Tracing a similar path, the $1 billion Penn East pipeline project is nearing final regulatory clearance to begin construction.

Taken together, these projects should allow Marcellus and Utica gas producers to ship an additional 7.5 billion cu. ft. of gas a day, increasing the region’s pipeline capacity by about a third, says Darren Horowitz, an analyst for Raymond James. “It is sorely needed as a long-term solution to free up highly economic Marcellus and Utica acreage,” Horowitz wrote in a late-September note. “Can producers fill these pipes? Is the pope Catholic?”

https://www.bloomberg.com/news/articles/2017-11-03/get-ready-for-an-appalachian-gas-bonanza

The European Commission is proposing to extend EU internal energy market rules to cover offshore gas pipelines, an EU document shows, its latest attempt to regulate Russia’s planned Nord Stream 2 pipeline to Germany.

The EU executive sees Russia’s plan to double the gas it could pump under the Baltic Sea to Germany, bypassing traditional routes via Ukraine, as undercutting EU efforts to reduce dependence on Moscow and its support for Kiev.

The move dovetails with the Commission’s proposal for a mandate from member states to negotiate with Russia over objections to the pipeline.

Even with the changes, EU regulators say they may need to seek talks with Russia as it cannot impose its law on the stretch of the pipeline that is outside its territory.

“This proposal does not solve all the problems … and some of those need to be negotiated,” an EU official said.

Under the proposed changes to the gas directive, seen by Reuters, all import pipelines would have to comply with EU rules requiring pipelines not be owned directly by gas suppliers, non-discriminatory tariffs, transparent operations and at least 10 percent of capacity be made available to third parties.

“The Gas Directive in its entirety … will become applicable to pipelines to and from third countries, including existing and future pipelines, up to the border of EU jurisdiction,” the proposals says.

The proposal will go to a vote on Wednesday at a meeting of EU Commissioners. If passed, it will go to member states and to European Parliament for approval.

EU regulators say they want the rules in place by the end of 2018 - early enough to apply to the Nord Stream 2 pipeline due to be completed by the end of the following year.

The Nord Stream 2 project, fully owned by Russia’s gas export monopoly Gazprom, is far from complying with the EU’s so-called third energy package rules. Russia has challenged these rules with the World Trade Organisation.

With the proposal, the Commission also challenges big member states, who have companies invested in the project.

Five European energy firms are financing the 1,225 km (760 mile) pipeline to carry 55 billion cubic meters of gas per year: German energy groups Uniper and Wintershall, Anglo-Dutch group Shell, Austria’s OMV and France’s Engie.

If the new rules are passed and the EU does not get a mandate for talks with Russia, it would be up to the member states involved, in this case Germany, to hold talks with Russia to apply the new rules, an EU official said.

The move extends legal uncertainty around the pipeline even as the project company plans to tap banks next year for financing of up to 70 percent of costs.

The proposed changes would do little to address the Commission’s concerns that Russia would divert gas now passing through Ukraine - depriving Kiev of lucrative transit fees.

http://www.reuters.com/article/us-eu-gazprom-nordstream/eu-plans-rule-change-to-snag-russian-pipeline-idUSKBN1D40RK

China’s Shanxi province has sold mining rights for 10 coalbed methane blocks, state-run Xinhua news agency reported, the first such deal after the government’s decision this year to use auctions as primary means for distributing rights.

The report said seven regional firms obtained the rights to the blocks, estimated to contain a combined total of 430 billion cubic meters’ worth of coalbed methane, but did not say how much the rights were sold for.

Shanxi has 8.3 trillion cubic meters of coalbed methane assets, accounting for one-third of the nation’s reserves.

http://www.reuters.com/article/us-china-coal/chinas-shanxi-province-sells-rights-for-10-coalbed-methane-blocks-xinhua-idUSKBN1D50IG

EOG’s main focus in recent quarters is its “premium” locations, defined as locations with locations with at least a 30% after tax ROR at $40 oil. The company is shifting to developing these wells, and adding further premium locations.

EOG has added two plays to its Permian inventory, with a combined 800 net locations and 750 MMBOE of resource potential.

https://www.oilandgas360.com/eog-resources-adds-two-new-premium-plays/

The new operator of the proposed Jordan Cove LNG export terminal in Oregon said Friday it has become more positive about its potential with the shorter route it offers to Asia and the interest it continues to receive from prospective buyers of its supply.

But Pembina Pipeline cautioned that development and construction costs would play into its decisions about future budgeting for the project.

Pembina did not immediately respond to a query for comment on whether the company, which took over the project after acquiring fellow Canadian pipeline operator Veresen last month, is fully committed to seeing Jordan Cove through to completion.

"Clearly, it is a huge project and we're looking at it carefully," Pembina CEO Mick Dilger said during a conference call with analysts to discuss third-quarter financial results. "It does have a significant burn rate, and we have to carefully review the risk-to-reward profile."

Dilger said that analysis would be done as part of the company's 2018 budget review. Burn rate refers to how quickly a developer spends its development and operating budget for a project, a factor that could lead to cost overruns. Jordan Cove has not yet reached a final investment for the project.

Jordan Cove would provide an outlet for Rockies gas producers who have been getting squeezed from all directions as a result of growing Permian production, steadily declining Southwest demand, as well as pushback from US Northeast expansions bringing more gas into the Midwest markets.

Basis at Rockies supply hubs has seen steady downward pressure this year as a result of increasing competition from other supply regions, data compiled by Platts Analytics' Bentek Energy show. Basis pricing at the Opal hub in southwest Wyoming averaged a 28 cents/MMBtu discount to Henry Hub through the first 10 months of the year, 10 cents weaker than the same time period in 2016, Platts Analytics data show.

INSUFFICIENT DEMAND CITED

In September, prior to the combination with Pembina, Veresen filed its second formal application to US regulators seeking approval of Jordan Cove, betting commercial support it received since its first request would push the project over the finish line after more than four years of trying.

The current crop of US LNG export developers that are still going through the regulatory process have been struggling amid fears of a global supply glut to sign long-term agreements with buyers to help raise the billions of dollars they need to build their terminals. Several, including NextDecade's Rio Grande LNG project in Brownsville, Texas, have delayed final investment decisions and extended expected in-service dates. Others are eyeing creative ways to prove viability, such as Tellurian's decision to buy gas-producing assets in Louisiana that will provide access to cheap supplies to its proposed Driftwood LNG export terminal. Tellurian also has floated the idea of fixed prices for shipments to Asia.

It was Jordan Cove's failure to show sufficient demand for its project to outweigh any negative impacts from the construction that was cited by the Federal Energy Regulatory Commission as a key reason for the agency's March 2016 permit denial. Less than two weeks later, Veresen announced that it had signed a preliminary agreement covering key commercial terms with one Japanese firm, Jera, and the next month it reached a preliminary agreement with another, Itochu. FERC refused to reconsider the initial application, which was filed in May 2013, but left open the opportunity for Veresen to file a new request.

With Veresen now under its fold, Pembina is left with the decision making about Jordan Cove's future.

The company reiterated Friday that it is targeting a final investment decision for 2019 and an in-service date of 2024. In a slide presentation accompanying its investor call, a plus sign was next to both dates, suggesting that FID and in-service could be pushed later.

In the meantime, the company is proceeding through the FERC process and working on finalizing existing agreements with offtakers, as well as securing agreements for its remaining capacity. The preliminary offtake deals with Jera and Itochu cover approximately half the 1 Bcf/d of capacity of Jordan Cove's initial phase and 77% of the capacity of the Pacific Connector pipeline that would supply feedgas to the terminal.

Executives said they expect a FERC permit decision during the latter part of 2018.

"I would characterize where we are now is having gone from neutral to favourable on the project," Dilger said. "We have been around the world meeting with potential customers. It does seem to us the timing and location of the project are favourable, and we are seeing quite a substantial interest in the project."

https://www.platts.com/latest-news/natural-gas/houston/pembina-says-jordan-cove-lng-terminal-budget-21450939

PetroChina and Beijing Enterprises Group Co are expanding liquefied natural gas storage capacity at a main import facility in northern China as the country boosts infrastructure to meet surging demand for the cleaner fuel.

China is facing a natural gas supply crunch this winter as an aggressive government push to heat millions of homes and thousands of industrial boilers with gas for the first time is driving demand for the fuel faster than the country’s infrastructure could cope with.

PetroChina and Beijing Enterprises Group will each add two 160,000 cubic-meter tanks at Caofeidian - an industrial landfilled zone in the northern city of Tangshan - to double the site’s storage capacity to 1.28 million cubic meters.

The terminal is a key supplier of imported LNG shipped in from Qatar to Australia and pumps the fuel via pipelines mainly to Chinese capital Beijing, the world’s second-largest gas consuming city after Moscow and burns roughly 9 percent of China’s total gas use.

“The expansion is aimed at boosting the much-needed storage capacity, as gas demand from Beijing and nearby northern cities surge during winter,” a PetroChina gas official, who declined to be named because he was not authorized to speak to media, told Reuters during a visit to the Caofeidian terminal.

A jetty receiving imported natural gas vessels is seen at PetroChina-controlled Caofeidian gas terminal in Tangshan, Hebei province, China October 17, 2017. Picture taken October 17, 2017. REUTERS/ Aizhu Chen

Beijing has encouraged companies to build both underground storage for pipeline gas and above-ground tanks for super-chilled LNG.

Once the four new tanks are added, Caofeidian will have the largest gas storage space among PetroChina’s three main terminals -- the other two in Dalian of Liaoning province and Rudong of Jiangsu, the official said.

Two other PetroChina officials, who also spoke on condition of anonymity, said the four new tanks would be ready around the end of 2019.

There was no immediate official comment from PetroChina and Beijing Enterprises, the Chinese capital’s dominant gas distributor that owns a small stake in the Caofeidian terminal.

PetroChina is also aiming to start building its fourth terminal in Shenzhen next year, after several delays due to land and regulatory issues, sources familiar with the plan said.

PetroChina’s three main operating terminals have a combined annual receiving capacity of 19 million tonnes, or 44 million cubic meters, although on average these facilities run at 40 percent of capacity.

http://www.reuters.com/article/us-china-lng-expansion/petrochina-beijing-firm-doubling-lng-storage-in-caofeidian-as-demand-rises-idUSKBN1D60VM

U.S. oil service companies face hard decisions in the coming weeks on whether to continue working for Venezuela’s state-run oil company PDVSA, and the prospect of hundreds of millions of dollars in write-offs for overdue bills.

The companies’ services are critical for Venezuela, which is struggling with a deep economic crisis marked by shortages of food and medicine. Oil accounts for over 90 percent of the nation’s export revenues.

Socialist President Nicolas Maduro on Thursday said the country plans to potentially restructure some $60 billion in bonds, widely seen as signaling a possible default that could affect other debt. New York-based investment firm Torino Capital estimates that, in addition to the bonds, Venezuela owes some $26 billion to creditors and $24 billion in commercial loans.

Oil services firms must now balance the prospect of future work in the OPEC-member South American nation against the risk of write-offs. Several have had to sharply write down the value of promissory notes received for past work in Venezuela.

Suppliers with overdue bills linked to the nation include oilfield services companies, storage facility operators, and shipping firms. All play key roles in keeping its oil flowing to world markets.

U.S.-based oilfield services provider Halliburton Co has a $727 million investment in Venezuela, including $429 million in outstanding bills, according to its most recent financial report.

Schlumberger has about $700 million at risk, including receivables and a promissory note for past work. Weatherford International has at least $158 million in outstanding bills, and Baker Hughes holds receivables and inventory valued at $100 million, according to their most recent financial reports.

PDVSA’s late payments for time-chartered tankers have grown in recent months as it put commitments to bondholders ahead of suppliers, according to shippers and a PDVSA source. The company is also losing other service providers over the lack of timely payments.

PDVSA could not be reached for comment.

Reduced access to infrastructure for blending and shipping oil in large tankers from the Caribbean has contributed to PDVSA’s declining crude exports, which fell to 1.47 million barrels per day (bpd) in the third quarter, 9.7 percent lower from the same period of 2016, according to Reuters data.

“They have sacrificed the company’s operations to pay bondholders,” the PDVSA source said.

NOTES AND PROMISES

After taking promissory notes from Venezuela earlier this year in exchange for $375 million in earlier debts, Halliburton wrote off $262 million of the notes. It is no longer seeking new work in the country, a source close to the matter said.

“We do not intend to accept further notes as payment if offered,” the company said in a regulatory filing last month.

A Halliburton spokeswoman declined to make an executive available to comment and declined to comment on the possibility of further write-downs. Baker Hughes confirmed the book value of its outstanding debts but declined further comment.

Weatherford and Schlumberger did not respond to requests for comment.

Shipping firms since last year have intermittently retained loaded oil cargoes as a way to pressure PDVSA for payment. The situation created bottlenecks to finding vessels for exports and domestic transportation, limiting shipments of Venezuelan oil.

Wait times for tankers that bring refined products and petroleum to Venezuela have extended in recent months to as much as 120 days, signaling slower payment, according to trade sources and Reuters data.

In total, there are 12 vessels carrying components of gasoline, naphtha and other products waiting since at least October to discharge, according to Reuters vessel tracking data.

http://www.reuters.com/article/venezuela-bonds-oilservices/rpt-u-s-oil-service-firms-face-hit-from-venezuela-debt-restructuring-idUSL1N1NC029

October tax receipts for shale-rich Oklahoma are up more than 10 percent from last year, though most of the recent gains came from vehicle taxes, data show.

The Oklahoma State Treasury said October receipts of $980.2 million were up 10.6 percent from last year, marking the first time in more than four years that monthly receipts grew by more than 10 percent.

"Such strong revenue growth is encouraging, with all four major revenue sources in positive territory," State Treasurer Ken Miller said in a statement.

Tax receipts come as the state works to close a budget gap. Oklahoma Gov. Mary Fallin called lawmakers to a special session in late September to address budget strains she said were critical. By her estimate, the state could face a $500 million shortfall next year because one-time funds were used to balance the books for the current fiscal year.

Miller's office said almost $18 million in gross receipts last month came from new legislation. About 65 percent of the new revenue came from a 1.25 percent state sales tax on motor vehicles, while a $5 vehicle registration added $1.9 million.

"The amount of new revenue gained during the month by boosting the 1 percent horizontal drilling gross production tax rate to 4 percent is not yet available from the tax commission," Miller's office reported.

Horizontal drilling is related to the energy sector. Taxes on oil and gas production generated $52 million in October, a jump of 48.4 percent from last year. Compared with September, however, tax collections from oil and gas grew just 3.7 percent.

Oklahoma is home to about 4 percent of the total petroleum reserves in the country and accounts for as much as 5 percent of the total crude oil production.

The state sits on the Anadarko shale reservoir. The U.S. Energy Information Administration predicts oil production there will increase about 2 percent and gas production by about 0.6 percent from October. Drilling services company Baker Hughes last week reported exploration and production activity is slowing down.

https://www.upi.com/Shale-rich-Oklahoma-sees-economic-gains/1241509968255/?spt=su&or=btn_tw

Brazil’s state-controlled oil company Petroleo Brasileiro SA has asked Odebrecht’s offshore drilling arm to halt operations of a rig, according to a document seen by Reuters on Monday, after an explosion there killed three people in June.

Petrobras also threatened to cancel contracts related to the Norbe VIII rig, according to an undated internal memo sent by Roberto Simoes, chief executive of Odebrecht Oil and Gas (OOG), Odebrecht’s offshore drilling unit.

Contract cancellations would be another blow for Odebrecht, which has been targeted in corruption probes in Brazil and elsewhere in Latin America.

OOG, which has struggled in the wake of a widespread slowdown in the region and restricted access to credit following the scandals, reached an agreement with creditors to restructure billions of dollars in debt earlier this year.

A workers’ union said in June that the blast occurred in the Marlim field during maintenance of a boiler. The rig began operating again in July, according to the memo, but it was unclear whether the work had been halted since then.

OOG declined to comment. In an email, Petrobras declined to comment on a request to halt operations but confirmed it has not made a decision about cancelling a services contract for Norbe VIII.

Simoes said the request to halt the rig came after an internal Petrobras commission studied the causes of the Marlim field accident, according to the memo.

Petrobras “concluded its work and requested that we stop operations of the drilling rig,” the statement said, adding that OOG was given 15 days to respond to the allegations.

Petrobras also said it could terminate the contracts related to the unit due to the incident, OOG said.

According to Simões, OOG set up its own commission to investigate the accident, and has taken steps to prevent similar incidents from happening again.

http://www.reuters.com/article/us-petrobras-odebrecht-rigs/petrobras-seeks-halt-to-odebrecht-drilling-after-accident-document-idUSKBN1D62QQ

Chevron Canada, a unit of global oil major Chevron Corp, is forging ahead with its first ever Canadian shale play development, targeting the East Kaybob region of central Alberta’s Duvernay formation.

The decision, announced by the company on Monday, is a rare bright spot for Canada’s oil industry, which was hard hit by the global crude price downturn. International energy firms sold off nearly $23 billion in assets this year alone.

Chevron will initially develop around 55,000 acres in the Duvernay. That could eventually spur more drilling in other parts of the 330,000 acre portion of the shale formation controlled by Chevron Canada, company spokesman Leif Sollid said.

He did not comment on Chevron’s expected production or capital spend in the Duvernay, citing corporate disclosure rules, but said it was a major step forward for the company which has spent three years appraising the Kaybob area.

“This is a very significant business opportunity for Chevron Canada and our very first foray into development in the liquids-rich Duvernay,” Sollid told Reuters.

“Since we began appraisal drilling we have made significant improvements in costs and cycle times by applying Chevron’s learnings in other North American shale plays including the Permian in Texas.”

The Duvernay formation is one of Canada’s top shale plays and holds the country’s largest marketable resources of unconventional light shale oil and condensate, according to the national energy regulator.

Canada’s energy industry is still dominated by the vast oil sands sector in northern Alberta, but investment is climbing in the Duvernay and Montney shale basins, which offer faster returns and lower capital requirements than the oil sands.

Chevron first acquired leases in the Duvernay around eight years ago and is now one of the region’s biggest landholders.

The company also holds undeveloped land in the Liard and Horn River basins in western Canada, a 20 percent stake in Canadian Natural Resource Ltd’s Athabasca Oil Sands Project and non-operator interests in a handful of deepwater projects off the east coast of Canada.

As part of Chevron’s East Kaybob development Calgary-based Pembina Pipeline Corp will spend C$290 million building infrastructure to ship and process gas and condensate, which is expected to be in service by mid to late 2019.

“We look forward to continuing to develop future Duvernay infrastructure needs over the long-term,” said Jaret Sprott, Pembina’s vice president of gas services.

http://www.reuters.com/article/us-chevron-canada-shale/chevron-green-lights-its-first-canadian-shale-development-idUSKBN1D62YZ

French oil and gas group Total and Italy’s Eni plan to start drilling in a joint exploration block off the coast of Cyprus by the end of this year or early 2018, President Nicos Anastasiades told French daily Le Figaro.

Anastasiades, who is in Paris for an official visit, met Total’s Chief Executive Patrick Pouyanne on Sunday ahead of his meeting with French President Emmanuel Macron on Monday.

Anastasiades told Le Figaro in an interview that Pouyanne said to him in the meeting that the oil majors would move ahead with plans to drill in Block 6 despite disappointing drilling results from Block 11.

“Yes, (block 11) was disappointing in terms of quantity, but the results are very promising for future drilling. It confirmed the presence of hydrocarbons in the Cyprus Exclusive Economic Zone, an extension of the Zohr field in Egypt,” Anastasiades said in the interview.

Eni was awarded the right in December 2016 to be operator of Block 6 with a 50 percent stake in partnership with Total.

Total was the operator of Block 11 in which it agreed a farm-in agreement with Eni for a 50 percent stake.

http://www.reuters.com/article/energy-cyprus-drilling/cyprus-president-says-total-eni-to-start-drilling-block-6-by-early-2018-le-figaro-idUSL5N1NC5VP

Italy could soon sell its stake in Eni to pay down debts, a source close to the matter told reporters on Monday.

The price of the stake in Eni has yet to be determined, and officials from Rome have declined to comment on the proposal. The Italian Treasury owns 4.34 percent of Eni.

"The idea is to get as much as possible as soon as possible, to cut the public debt causing the least possible political impact," the source said.

Italy’s financial goal for 2017 involved raising 3.4 billion euros to pay off public debt, an amount totaling to 130 percent of the national gross domestic product. So far, Rome is far behind on that fundraising agenda.

Oil and gas companies themselves have faced tough financial times in recent years as barrel prices hover in the $55-$60 range, compared to pre-2014 heights of over $100. In 2015 and 2016, analysts and credit watchers began asking tough questions about the sustainability of the generous shareholder payouts. Eni became the first to reduce its dividend in 2015. BP offered a scrip dividend to its shareholders, a half-measure that offers equity instead of cash. Statoil did the same.

But times have changed, and the oil majors have made a lot of progress in cutting costs and improving their financial health. The results are evident. BP and Statoil just announced in recent days that they would end their scrip dividend program and pay cash to shareholders. BP even said it would repurchase shares equivalent to the amount it issued during its scrip program.

The Italian government’s cash flow problem is more chronic and less related to the health of the world’s energy markets. Italy, Greece, and Spain have been grappling with slow economic growth and high unemployment since the global economic recession of 2008.

https://oilprice.com/Latest-Energy-News/World-News/Italy-May-Sell-Eni-Stake-To-Pay-Off-National-Debt.html

Comparative inventory (C.I.) has been dramatically reduced in 2017. Levels have fallen 159 mmb since February and are now approaching the 5-year average for the first time in nearly 3 years.

The U.S. Over-Supply of Oil is Ending. Source: EIA and Labyrinth Consulting Services, Inc.

An interpreted yield curve that correlates C.I. and WTI price is developed by cross plotting the same data without the time dimension. The yield curve may provide price solutions to inventory reduction assumptions in the near term.

Crude + Product Comparative Inventory Have Fallen 159 mmb in 2017. C.I. Could Reach the 5-Yr Avg By & $70 WTI Prices by Early 2018. Source: EIA and Labyrinth Consulting Services, Inc.

Accordingly, if C.I. continues to fall at the 9-month average of 4 mmb/week, oil prices may be approximately $67 per barrel by the end of December. If C.I. falls at the 8 mmb/week average since late September, WTI could approach levels not seen since before the price collapse in late 2014.

Lots more plus many charts:-

https://oilprice.com/Energy/Oil-Prices/Can-WTI-Hit-70-In-2018.html

A 2014 photo shows a worker waiting to connect a drill bit on Endeavor Energy Resources's Big Dog Drilling Rig 22 in the Permian basin outside of Midland, Texas: Bloomberg photo by Brittany Sowacke

Texas oil companies have hired more than 30,000 workers over the past year, a sharp turnaround after they laid off a third of the industry’s statewide workforce during the oil bust.

The number of Texas oil and gas workers reached more than 222,000 in September, up 16 percent from about 192,000 in the same month last year, the lowest point since the Great Recession in 2009.

At the peak of the oil boom in 2014, Texas had more 295,000 jobs, according to Karr Ingham, a Texas economist who studies the oil industry.

Ingham’s Texas Petro Index, a measure of activity in the business of pumping oil from the earth, rose for the 10th consecutive month in September, to 181.4 points, up 21.4 percent than September 2016.

“Crude oil prices in Texas have been the essence of stability for more than a year,” Ingham said in a statement. “Demand is beginning to show signs of recovery and foreign oil suppliers led by OPEC appear to be committed to maintaining announced production cuts.”

https://www.energyvoice.com/oilandgas/americas/155409/texas-oil-companies-hire-30000-past-year-amid-crude-price-recovery/

Leasing fees for onshore storage tanks to store fuel oil in Singapore are being renewed at much lower rates, because of ample availability of floating storage capacity and narrowing margins between cargo and ex-wharf prices, industry sources said over the week.

Industry sources suggested that between S$4/mt ($2.93/mt) and S$5.50/mt per month is the current market for one to two year leases, depending on how many turns per month are included and the attractiveness of the terminal, down from monthly rates of S$8/mt or more previously signed for periods of one to three years.

Sources particularly pointed to ongoing renewal negotiations for lease agreements starting next year at Universal Terminal as representative of the current storage fees.

Shell was said to have recently renewed its lease at S$5.50 or less, while BP and Lukoil are currently negotiating and are considering not renewing their leases which expire at the end of 2017. Glencore's lease is believed to be expiring in April 2018.

Each company currently has around 300,000 cu m of capacity at Universal, which attracts premium rates due to its VLCC berths and operational efficiency.

None of the companies mentioned above were prepared to comment on their commercial arrangements, but most did confirm that rates for new leases had fallen.

"What has changed the balance of power in the landed tank lease negotiations is the abundance of floating storage now being offered. It's not as convenient as landed storage but the cheap floating storage gives traders another option," one source explained.

The monthly lease for a floating storage in comparison, is less than US$3/mt, according to one trade source.

"And there are other landed storage options available in the [Singapore] Strait and places like Fujairah where traders can store and blend at cheaper rates," he added.

As well as competition from other storage options, traders pointed to the narrowing margins in Singapore between cargo and ex-wharf prices as another reason behind the fall in storage fees.

"The Singapore market has become incredibly efficient and transparent, it's easy to see that with the cargo to ex-wharf spread (which can be viewed as the break-bulk profit margin) often less than US$2/mt, and the backwardated market structure, one is reliant on the blending to make a profit," one trade source said.

"It's possible Singapore could become much more like Fujairah, with not all the tanks leased all the time, or at least not fully used all the time, so short-term 'spot' leases will become more common. We're already seeing that in Singapore at rates of around US$2.50/mt per month including one turn," the trade source said.

https://www.platts.com/latest-news/oil/singapore/fuel-oil-storage-costs-fall-in-singapore-on-overcapacity-27885881

Exxon Mobil Corp.’s deal in January for a swath of Permian Basin drilling real estate came with a sweetener for the sellers. The heirs of oil tycoon Perry Bass will get $1 billion in cash by 2032 -- if drilling goes well for Exxon.

That payout would be on top of the $5.6 billion in Exxon shares the Bass family is getting for Bopco LP and other New Mexico and West Texas holdings in the Permian, the most productive U.S. oilfield.

Such payouts -- earnouts or contingent payments in M&A jargon -- have become much more prevalent in the oil patch this year as deal-hungry explorers, services providers and pipeline operators hedge their bets on the future of shale. Some depend on oil or gas prices rising. Others are tied to future profits or production volumes. Most share the same premise: The seller gets more money if the deal goes well for the buyer.

“I sometimes suggest them as alternatives to my clients,” said Michael Byrd, an Akin Gump Strauss Hauer & Feld LLP partner in Houston who advises on oil and gas deals. “They are used to bridge the bid and ask.”

At least 24 oil and gas deals in the U.S. and Canada with a combined value of more than $25 billion have included earnouts so far this year, according to a review of deal announcements. That review turned up only nine such deals, totaling more than $5 billion, over the same period last year.

The rise in earnouts coincides with a slump in dealmaking in 2017 after last year’s rebound in oil and natural prices spurred a takeover boom. North American energy mergers totaled about $135 billion through the end of October, a decline of more than 25 percent from a year earlier, according to data compiled by Bloomberg. U.S. shale producers’ rising output contributed to a global oil glut that sent crude prices tumbling this summer before rallying in the fall.

That volatility has created uncertainty that earnouts are designed to address.

“In some cases, they are used to reduce exposure to large commodity price swings,” Byrd said. “While in others, they are used to protect against uncertainty as to the future development potential of currently undeveloped acreage.”

Year’s Biggest

The largest deal with an earnout this year was Cenovus Energy Inc.’s $13.3 billion purchase in May of Canadian oil assets from ConocoPhillips, which will get extra payments over five years if prices for West Canada Select top C$52 ($40.53) a barrel. If oil averages C$60 a barrel, for example, Conoco would get about C$200 million a year, Conoco executives told analysts when announcing the deal in March. West Canada Select was trading at C$55.18 on Monday, according to data compiled by Bloomberg.

“We did the Canadian transaction because they were willing to put in a contingent payment,” Conoco Chief Executive Ryan Lance said at an energy conference in June, according to a transcript compiled by Bloomberg. “They were willing, and we get half of that upside. So, that’s the only way we would sell oil-based assets in this kind of a market.”

Conoco’s $2.7 billion sale of its natural gas holdings in New Mexico to Hilcorp Energy Co. also had an earnout. So did many others: Laredo Petroleum Inc.’s $1.8 billion sale of its stake in pipeline operator Medallion Gathering & Processing LLC to Global Infrastructure Partners; Noble Energy Inc.’s $1.1 billion sale of natural gas assets in West Virginia and Pennsylvania to Quantum Energy Partners LLC; and Targa Resources Corp.’s $565 million purchase of most of pipeline operator Outrigger Energy LLC.

Earnouts can make sense in deals for companies operating in newly developing basins where there isn’t a lot of historical drilling data, said Ali Akbar, a managing director with Royal Bank of Canada’s RBC Capital Markets who specializes in energy pipeline deals.

‘Fair Value’

They help sellers “get to what they deem to be a fair value,” Akbar said. “Buyers can feel that they didn’t overpay upfront. So basically, a win-win.”

RBC advised Targa on its purchase of Outrigger, which controls a network of oil and gas gathering pipelines in a fast-growing portion of the Permian known as the Delaware Basin. The deal calls for Targa pay as much as $935 million more in 2018 and 2019 to Outrigger’s former owner, Denham Capital Management, depending on how much it makes on contracts with the customers Outrigger had when the deal closed in March. New customers don’t count.

The earnout “de-risked” the transaction, Targa Chief Financial Officer Matthew Meloy said in a conference call with analysts in January.

“Strong performance from those contracts would be very good for the sellers and very good for our” investors, Meloy said. “The bigger that payment is, the more cash flow there is.”

Earnouts aren’t headache free.

They can be tough to negotiate because parties have to agree on what will trigger payouts, how big they will be and how long they will last. Sellers often want a say in how the buyer operates the target to assure they get paid, a concession nobody likes to make.

Buyer Beware

Earnouts also can have potentially negative tax consequences for the buyer, said John Grand, a Vinson & Elkins LLP partner in Dallas who advises on energy deals. While earnout payments can be deducted as part of the overall purchase price, the extra revenue triggering them may be taxed as ordinary income at a much higher rate.

They tend to be an option of last resort in negotiations for a company that failed to sell in an auction or had a deal with another buyer fall through, according to Grand.

“Buyers need to beware,” he said.

The buyout firm Quantum Energy Partners had a tentative agreement this year to sell Permian basin explorer ExL Petroleum Management to a Russian investment firm that fell apart because of regulatory concerns, people familiar with the matter said in June. Quantum then agreed to sell ExL to Carrizo Oil & Gas Inc. for $648 million plus as much as $125 million more in earnout payments, depending on future oil prices.

“Both sides, generally, prefer not to have earnouts,” Grand said.“It’s hard to really put a value on what you are getting and what the likelihood of getting that payment is.”

https://www.bloomberg.com/news/articles/2017-11-06/oilpatch-dealmakers-agreeing-to-pay-more-later-amid-m-a-slump

Nigeria’s oil minister will visit the Niger Delta this week in a bid to stave off a threat of more insurgent attacks in the area, and said that without more investment it would be a struggle to ease tensions and develop its main crude producing region.

The Niger Delta Avengers, whose attacks on energy facilities in the region last year helped push Africa’s biggest economy into recession, said on Friday it had ended its ceasefire in its campaign for more of Nigeria’s oil earnings.

“We’re constrained by cash,” Emmanuel Ibe Kachikwu, the minister of state for petroleum, told Reuters in an interview on Monday when discussing efforts to develop the Delta. “We’ve scurried around for some money just to begin the process.”

He said he would meet representatives of the militants and other stakeholders during a visit to the region on Nov. 9.

The minister said the government needed to develop its oil and economy to deliver on promises of more cash for the Delta, which rights groups say has long suffered from pollution and poor investment despite being the source for much of Nigeria’s oil output of around 2 million barrels per day (bpd).

Kachikwu said a return to violence by the militants would be “mutually destructive”, adding: “I am sure that like they did the last time, when they see a concrete action plan they would listen.”

Attacks in the oil producing region drove Nigeria’s oil output down to close to 1 million bpd. The Organization of the Petroleum Exporting granted Nigeria an exemption from a global deal to curb output to help it recover.

In its race to rebuild, Kachikwu said Shell and Eni should press on with developing oil prospecting licence (OPL) 245. The $1.3 billion award of the block in 2011 is subject to corruption investigations and court cases. The firms deny wrongdoing.

“It’s been allocated, and there are development plans for it (the block) and those development plans should go forward,” Kachikwu said. “The development of assets should not suffer because we are dealing with a legacy transparency issue.”

The minister said he intended to launch a “roadmap” in January inviting investors to fund repairs and upgrades to pipelines and oil depots, mirroring efforts that aim to draw $1.5 billion to $2 billion into Nigeria’s ailing refineries.

Kachikwu said the plans would not involve selling state-owned stakes but attracting private capital was essential.

“We don’t have the resources, and we don’t have the time to raise the resources, to revamp the sector,” he said.

On changes in the industry, the minister said revisions to oil contracts and operations at state oil company NNPC had saved money, citing deals to exchange crude for fuel, dubbed “direct sale, direct purchase”, that saved the state $1 billion.

Nigeria has called for early talks to renew oil licenses held by Shell, Total and others. Licences for several key fields expire in two years and oil firms are typically reluctant to make big investments without long-term assurances.

Kachikwu said such talks could be concluded by the first quarter of next year, although negotiations that are handled by the Department of Petroleum Resources had not yet started.

http://www.reuters.com/article/us-nigeria-oil-kachikwu/more-oil-cash-needed-in-nigerias-delta-to-avert-new-conflict-says-minister-idUSKBN1D71QU

BP helped Mexico execute its 2018 oil hedge, the biggest in the industry, becoming the second major after Shell to participate in the highly coveted program and challenging the traditional role of banks in the operation.

Three industry sources said BP has become a participant of the 2018 program on which Mexico spent some $1.26 billion to hedge its 2018 oil exports against oil price falls as part of government’s efforts to stabilize its budget.

BP declined to comment.

BP joins rival Royal Dutch Shell (RDSa.L), which made a first foray last year to become the first major to challenge years of dominance of big Wall Street banks in the program.

Shell declined to comment.

Banks such as Goldman Sachs (GS.N), Citi (C.N) and JPMorgan (JPM.N) have dominated Mexico’s program for years but their role has diminished with tighter regulations on bank commodity trading, including a near total ban on proprietary trading.

Commodities-related revenue across Wall Street banks broadly tumbled in the first half of 2017 to its lowest level since at least 2006, consultancy Coalition said in a report.

This was due mainly to a drop in client activity and a slump in trading performance in the energy sector.

Mexico did not disclose the volumes of oil hedged nor detail of the average price per barrel of put options that the government has purchased.

In September, the finance ministry proposed a 2018 budget that based expected oil export revenue on an estimate of $46 per barrel. In October, members of Congress increased that estimate to $48.5 per barrel as global oil prices rose.

On Tuesday, Brent oil prices stood at $64 per barrel.

For more than a decade, Mexico’s government has paid for a hedge every year in a bid to guarantee its revenues from oil exports by state company Pemex. The program is seen as the world’s top sovereign derivatives trade.

Last year, the government bought put options at an average price of $38 per barrel to cover 250 million barrels of crude at a cost of $1.03 billion and underpin the 2017 budget, which was based on an average price of $42 per barrel.

This year, Mexico is on track to not see any income from its oil hedge as prices for Mexican crude trade well above $50 per barrel. In 2016, Mexico saw a $2.65 billion payout from its oil hedge.

Mexico used to receive about one-third of federal revenues from oil sales, but it now funds less than one-fifth of the budget with oil sales after the collapse of crude prices in late 2014 and a decline in production.

http://www.reuters.com/article/us-mexico-oil-bp/bp-joins-shell-in-helping-mexico-execute-oil-hedge-sources-idUSKBN1D71HG

Brazil’s state-run oil company Petróleo Brasileiro SA on Tuesday started the sale of its stake in an African oil exploration venture as part of a wider divestiture plan.

Petrobras, as the company is known, is looking to sell its 50 percent stake in Petrobras Oil & Gas BV, or Petrobras Africa. Grupo BTG Pactual SA holds a 40 percent stake in the joint venture, while Helios Investment Partners owns the remaining 10 percent.

Petrobras Africa participates in two deepwater oil exploration blocks off the coast of Nigeria.

http://www.reuters.com/article/us-petrobras-divestiture-petrobras-afric/brazils-petrobras-kicks-off-african-oil-venture-stake-sale-idUSKBN1D71IK

Container shipping group CMA CGM said on Tuesday that it had decided to use liquified natural gas (LNG) to power nine extra-large vessels it has ordered, in what would be a first for the industry.

CMA CGM had announced in September the order for nine giant ships, but said it had not yet chosen what fuel to adopt.

LNG has been touted as a solution for shipping firms as an alternative to bunker fuel before new international standards on fuel emissions take effect in 2020.

http://www.reuters.com/article/us-cmacgm-ships-lng/cma-cgm-chooses-lng-as-fuel-for-big-ship-order-idUSKBN1D7128

International regulation to cut sulfur in marine fuel is intended to cut emissions that health authorities blame for respiratory and heart diseases

The refining industry is facing its biggest disruption in years from a looming international air-pollution regulation aimed at slashing the amount of sulphur in marine fuel for ocean-going ships.

The regulation doesn’t go into effect until 2020, but its reverberations are already being felt. Analysts predict it will widen the gap between the refining world’s winners and losers, making some richer while pushing others to the brink.

Some larger companies, including ExxonMobil Corp.,Total SA and Repsol SA have invested billions in recent years to upgrade refineries, which will allow them to produce more lower-sulphur fuel and other products. They say they are prepared for the regulations, which are set by the International Maritime Organization and meant to reduce emissions that health officials blame for respiratory and heart diseases.

Some smaller companies, including Philadelphia Energy Solutions, the largest refinery on the U.S. East Coast, haven’t yet begun to make the costly improvements.

“It’s the biggest change to hit the industry in a while,” said Clint Follette of Boston Consulting Group. “At this point, it’s too late for most companies to put in those kinds of investments before 2020.”

The International Maritime Organization, the United Nations’ shipping regulator, last year mandated that oceangoing vessels cut the sulfur content in their fuel by more than 85% starting in 2020. The world’s 50,000 merchant ships can either undergo costly retrofits to their exhaust systems, or use cleaner fuels such as low-sulphur diesel.

Most large ships now use what is known as bunker fuel, a thick, sulphurous type of fuel that is often composed of residual oils, or the leftovers after diesel and gasoline have been separated from crude oil through refining.

Shipping companies are expected to opt for cleaner fuels, which will shrink the market for bunker fuel. Shippers consume as much as 4 million barrels per day of bunker fuel, and the regulation could cut demand by as much as half, analysts say.

That is bad news for simpler refineries in Europe and the U.S. East Coast, which will be stuck a glut of high sulphur fuel leftovers they will be forced to sell at huge discount, Mr. Follette said.

That is bad news for simpler refineries in Europe and the U.S. East Coast that aren’t able to process the dregs of the barrel into more valuable fuels and which will stuck with a glut of high sulphur fuel leftovers they will be forced to sell at huge discount, Mr. Follette said.

It is good news for the U.S. Gulf Coast, already the money-making center of the American refining industry. Many refineries there are more complex, meaning that they have technology that can take heavy and sour crude and turn it into more profitable, light products, in addition to bunker fuel.

Companies including ExxonMobil, Chevron Corp. , Marathon Petroleum Corp. and Valero Energy Corp. have some of the nation’s most complex refineries, according to Stratas Advisors global refinery rankings.

In addition to its existing assets on the Gulf, Exxon, in anticipation of the new rules, is investing more than $1 billion in new equipment that will be able to produce lower-sulphur fuels at a refinery in Antwerp, Belgium.

Others in Europe are also investing. Total has invested $1.31 billion at its refinery complex in Antwerp to increase its diesel capabilities and cut heavy- oil production.

Dario Scaffardi, executive vice president at Saras, said “small and unsophisticated” refiners will “all have a problem” in 2020, because “high sulphur fuel oil will be a product without a home.”

The change comes at a bad time for the beleaguered East Coast refining sector, where many refineries have shut down in recent years.

Philadelphia Energy Solutions, a joint venture of private-equity firm Carlyle Group LP and Sunoco Inc., is one of the least complex major refineries in the U.S., according to Stratas Advisors.

The facility processes 335,000 barrels per day and primarily makes gasoline. It is already mired in debt, due to higher costs to secure crude on the East coast than elsewhere in the U.S., declining gasoline consumption and millions it had to spend to comply with earlier regulations to blend ethanol into their fuels.

The company played down the impact of the new rule, saying the U.S. is producing a lot of less sulphurous sweeter crude oil, the type the facility prefers and that while it will reduce the market for bunker fuel, it will increase the market for cleaner fuels.

“The IMO 2020 regulation will create new demand for diesel until the shipping industry adapts to the new regulation,” it said in a statement.

https://www.wsj.com/articles/pollution-rule-is-boon-for-richest-refiners-blow-for-weakest-1510059604

China’s October crude oil imports slid to their lowest monthly level in 13 months, tumbling from a near record in September, as buying from independent refiners slowed with their import quotas draining away.

Data from the General Administration of Customs showed on Wednesday that imports stood at 31.03 million tonnes in October, or 7.3 million barrels per day (bpd), up from the same month a year earlier but well below about 9 million bpd in September.

“Lower imports reflected less purchases from independent refineries as many of them are running out of crude quota for this year,” said Li Yan, oil analyst with Zibo Longzhong Information Group.

The lower imports in October were a surprise, the analyst said, as crude demand usually picks up in the fourth quarter with refiners’ processing rates strong.

The import data came as China’s Commerce Ministry set its 2018 crude oil import quota for non-state companies at 142.42 million tonnes, an increase of more than 50 percent, with markets expecting China to buy more crude this year.

Meanwhile gas arrivals including pipeline imports and LNG shipments reached 5.81 million tonnes, retreating from September but up from only 3.82 million tonnes last year.

For the year to date, natural gas imports grew 25 percent to 54.16 million tonnes, higher than last year’s total import volume of 54 million tonnes and hitting a record.

Surging gas consumption from both residential households and the industrial sector has pushed up spot liquefied natural gas (LNG) prices and led to worries that the world’s largest energy consumer might faces winter shortages.

CNPC, one of the country’s largest gas producers, already plans to cut natural gas supplies to industrial users.

http://www.reuters.com/article/us-china-economy-trade-crude/china-oct-crude-oil-imports-drop-to-lowest-in-more-than-a-year-idUSKBN1D80EE

Group raises forecast for shale oil output in annual report. Shale producers show ‘resilience and ability to bounce back’

OPEC said shale oil production will grow considerably faster than expected over the next four years after the group’s output cuts triggered a crude-price recovery that helped U.S. producers.

North American shale output will soar to 7.5 million barrels a day in 2021, the Organization of Petroleum Exporting Countries said in its World Oil Outlook report on Tuesday. That’s 56 percent higher than it forecast a year ago. The revised outlook illustrates OPEC’s dilemma: with supply curbs also helping its rivals, demand for the group’s crude will remain little changed until shale oil output peaks after 2025.

U.S. shale oil “most strikingly” exceeds previous expectations after showing the “resilience and ability to bounce back,” OPEC said. “This growth is heavily front-loaded, as drillers seek out and aggressively produce barrels from sweet spots in the Permian and other basins.”

OPEC assumes shale oil production growth will mostly originate from the U.S., with some contribution from Canada, Argentina and Russia over the forecast period to 2022. North American shale production for 2017 is now seen at 5.1 million barrels a day, up by almost a quarter from last year’s World Oil Outlook report.

OPEC and its partners, including Russia, are meeting in Vienna on Nov. 30 to decide whether to extend the deal to curb production beyond the end of March. Since Jan. 1, they’ve targeted output cuts of about 1.8 million barrels a day in a bid to reduce global stockpiles.

Brent crude has rebounded more than 10 percent this year, trading at more than $62 a barrel in London.

OPEC expects shale oil production to peak after 2025 and decline from about 2030. OPEC will then be required to increase its own output from about 33 million barrels a day in 2025 to 41.4 million in 2040, according to the report.

OPEC raised its forecast for global oil demand by 2.3 million barrels a day in 2021 compared with last year’s report. The group said demand growth will be particularly robust in 2020 as regulations to reduce shipping pollution kick in, leading to higher refinery runs to provide the required fuels.

OPEC also raised its oil demand forecast in 2040 by 1.7 million barrels a day to about 111 million barrels. China and India will lead the demand growth, offsetting declines in developed nations, it said.

https://www.bloomberg.com/news/articles/2017-11-07/opec-sees-u-s-shale-oil-powering-ahead-after-cuts-boost-prices

Crude oil has surged higher while the market is trying to quantify the potential risks to supply following the weekend power grab by the king and crown prince of Saudi Arabia. Last month's supply disruption in Northern Iraq, the US' hardened stance towards Iran, and now Saudi Arabia have all helped to create a perfect tailwind for oil bulls.

Since Iraqi forces retook the Northern Iraqi city of Kirkuk on October 16, Brent crude has rallied by more than 13%. Actual supply disruptions during that time have amounted to just a few hundred thousand barrels, and as such cannot justify an oil curve that increasingly points towards supply scarcity.

A combination of supply disruptions, strong demand growth, falling global inventories, and increased geopolitical risks have led to surging investment demand. Due to liquidity constraints further out the curve, speculative demand tends to be concentrated at the front of the curve thereby giving a potential false sense of the market being tighter than it actually is.

In a yield-hungry world, these latest developments have led to surging investment demand with investors seeking to capture the positive roll yield associated with a market in backwardation.

Raised geopolitical risks have created a perfect tailwind for bulls already long a record 530 million barrels of Brent as it sidelines potential short-sellers at risk of being caught should worries about supply disruptions turn real.

In the week to October 31, before the latest surge, hedge funds owned a record 530 million barrels of Brent crude with the total including WTI crude oil reaching 840 million barrels. Brent crude oil looks the most stretched with the net-long as percentage of total open interest on ICE hitting a record 18% while the long-to-short position ratio reached 10 to 1, the highest since February 24.

Brent crude is trading steadily today after reaching a fresh two-year high earlier. The net-long is likely to have expanded further since last Tuesday with the higher highs attracting additional technical buying from CTAs and momentum funds. On that basis, a considerable downside risk is building for when worries related to Saudi Arabia begin to ease.

With every new high, the risk RSI is looking increasingly stretched – not only in crude oil but also across the products.

https://www.tradingfloor.com/posts/speculative-oil-bets-creating-false-sense-of-a-tight-market-9031611

Gasoline flows to the US and east coast of Canada from Europe and arriving in November amount to around 284,000 mt so far, according to data from cFlow, S&P Global Platts trade flow software.

Six vessels carrying gasoline left Northwest Europe over the past eight days to go to North America, all Medium Range tankers. Five were heading to the US Atlantic Coast, while one was going to Canada.

That represented a change from the previous four weeks, when slightly more than half of the tankers bound for North America were headed to Canada.

Last week, the arbitrage to the US from Europe was said by sources to be close to opening, with the US the natural location for the product as Asia and Latin America have taking less product, according to sources, though spot demand was up across several markets.

Gasoline was also supported by stock draw-downs in the US, where countrywide gasoline stocks fell for the sixth consecutive week.

However, inventories of gasoline in the Amsterdam-Rotterdam-Antwerp hub were broadly stable, rising 5,000 mt, or 0.7%, to 774,000 mt in the week ended November 1, data from PJK International showed. ARA gasoline inventories are 4.8% lower than the 813,000 mt on November 2, 2016, according to the data.

https://www.platts.com/latest-news/oil/london/nwe-gasoline-flows-to-north-america-at-around-26835033

China has raised its 2018 crude oil import quota for “non-state trade,” generally meaning independent refiners, by 55 percent over 2017, raising the clout of the independents in the global market after a setback this year.

The move took market participants by surprise after Beijing cut the quotas to independents for 2017. The annual quota setting, announced earlier than usual, is a sign the government is relaxing its policies towards the independent refiners after the cuts and after banning them from exporting fuel this year.

The Ministry of Commerce said on Wednesday companies can start applying for quotas for 2018 totaling 142.42 million tonnes, or about 2.85 million barrels per day (bpd), up from 91.73 million tonnes for 2017.

The ministry did not provide a detailed breakdown of quota recipients, but they should include mostly independent refiners, which in 2017 made up around two-thirds of the total.

The announcement follows a recent state media report that China’s increasingly influential independent refineries have sought changes to oil quota polices to help them plan procurement and production in advance.

Quotas for some of these independents, also known as “teapots”, were cut by nearly 17 percent in 2017 versus 2016 because they under-used the earlier permits.

“Teapots like us may get a bit more quota next year after Commerce Ministry cut back our volumes in 2017,” said a procurement manager with Shouguang Luqing Petrochemical Co, a teapot based in the eastern Chinese province of Shandong, home to a number of the independent plants.

BOOST FOR RUSSIAN, ANGOLAN OIL

“It’s an improvement to set the annual volumes earlier. But the volumes are much larger than expected,” said Harry Liu of consultancy IHS Markit.

Higher quotas should boost imports of ESPO crude which loads from Russia’s Far East and crude from Angola, favorite supply sources for the independents that have also been drawing barrels from the Americas and the Middle East.

“Margins for fuel is really strong in (the fourth quarter) as crude prices pick up. We have already run out of quota this year. So if we get higher quota, we will import more crude in 2018, especially ESPO,” said the Shouguang manager, who declined to be named because of company policy.

The new quotas are equal to about one-third of China’s imports during the first nine months of the year.

One of the new recipients is likely to include a greenfield refinery backed by Zhejiang Rongsheng Group, a privately owned petrochemical company, said a source familiar with the matter.

Zhejiang Rongsheng may start trial operation of a 400,000 bpd plant in east China towards the end of 2018 and that would be joined by Hengli Petrochemical Group’s planned 400,000 bpd refinery in northeastern city of Dalian in the third quarter, three sources familiar with the plants said.

The Commerce Ministry said the quotas will be issued in batches, with the first lot based on companies’ actual purchases during the January to October period this year.

Companies without any import record will be banned from new quotas for 2018 and those which under-use quotas are required to return the unfinished permits.

http://www.reuters.com/article/us-china-oil-imports/china-sets-2018-non-state-crude-oil-import-quota-55-percent-higher-than-2017-idUSKBN1D808P

U.S. natural gas production growth is expected to surge in 2018, after rising more modestly in 2017, the U.S. Energy Information Administration (EIA) said in a monthly report Tuesday.

U.S. dry natural gas production was forecast to rise to 73.45 billion cubic feet per day (bcfd) in 2017 from 72.85 bcfd in 2016, according to the EIA’s Short Term Energy Outlook (STEO).

The latest November output projection was a little lower than EIA’s 73.63-bcfd forecast in October and falls short of the record high 74.14 bcfd produced on average in 2015.

The EIA also projected natural gas production would rise to 78.90 bcfd in 2018, up from a forecast of 78.49 bcfd issued in October.

Total gas consumption in the U.S. is likely to fall slightly in 2017 to 73.06 bcfd from 75.1 bcfd a year earlier. Total consumption is expected to rebound in 2018 to 76.83 bcfd.

However, natural gas usage in U.S. homes is expected to grow in both years, rising slightly to 11.90 bcfd in 2017 and climbing to 12.89 the following year.

“We foresee a likely rebound in average household residential consumption of natural gas this winter, as we expect temperatures to be closer to average and therefore colder than last year,” said John Conti, acting EIA administrator.

http://www.reuters.com/article/us-usa-natgas-eia-steo/u-s-cuts-natgas-2017-output-growth-forecast-raises-2018-outlook-idUSKBN1D72HH

The American Petroleum Institute reported Tuesday that U.S. crude supplies dropped by 1.562 million barrels for the week ended Nov. 3, according to sources. The API data also showed a rise of 520,000 barrels in gasoline stockpiles, while inventories of distillates lost 3.13 million barrels, sources said. 

Supply data from the Energy Information Administration will be released Wednesday morning. Analysts polled by S&P Global Platts expect the EIA to report a fall of 2.7 million barrels in crude inventories, along with declines of 2.25 million barrels for gasoline and 1.85 million barrels for distillate supplies.

https://www.marketwatch.com/story/api-report-reveals-drop-in-crude-inventories-but-jump-in-gas-stocks-2017-11-07

Several US liquefied natural gas (LNG) export project developers are taking part in the US presidential trade mission to China in an attempt to secure deals and grab a bigger part in one of the world’s largest LNG import markets.

The trade mission is part of U.S. President Donald Trump’s first state visit to China with Chinese President Xi Jinping.

Led by U.S. Secretary of Commerce Wilbur Ross, the trade mission participants, among others include Cheniere Energy’s chief executive Jack Fusco, Texas LNG chief operating officer Langtry Meyerand,  Frederick Jones, founder and chief executive of Delfin Midstream and Seifollah Ghasemi, chief executive of LNG equipment provider Air Products.

Delegation meetings are taking place on November 8 and 9 in Beijing, China.

Langtry Meyer of Texas LNG said in a statement that the company looks forward to representing the U.S. LNG industry and “promoting our China-focused strategy which includes LNG offtake, possible capital investment, and liquefaction module fabrication.”

“Our partnerships with Chinese companies will contribute to U.S – China bilateral trade growth and enable both nations to reap economic and environmental benefits,” Meyer said.

http://www.lngworldnews.com/us-lng-export-project-developers-join-trumps-china-trade-mission/

As leaders in the U.S. House take up an offshore drilling bill, pressure has mounted on the U.S. government's lack of oversight for protection of public lands.

The Accessing Strategic Resources Offshore Act, or ASTRO, would limit the presidential authority to put parts of the Outer Continental Shelf off limits to oil and gas drillers and give the Interior Department the authority to move ahead with new lease sales "as soon as practicable," but no later than a year after the announcement of intent.

House leaders scheduled a markup hearing on the measure for Wednesday. Miyoko Sakshita, the oceans project director at the Center for Biological Diversity, said the ASTRO Act was a giveaway to the oil and gas industry.

"Bishop's bill is a truly shocking attack on our government's ability to protect America's public lands and oceans from dangerous drilling," she said in a statement.

Rep. Rob Bishop, R-Utah, is the chairman of the House Natural Resources Committee, which is reviewing the bill. The majority of Bishop's fundraising comes from the oil and gas industry. In his support of the bill, the chairman said the ASTRO Act would "make the U.S. energy dominant."

The American Petroleum Institute estimates the oil and gas industry has added $1.3 trillion to the U.S. economy since 2015. Supporters of the measure said opening up more areas to drillers could create more than 800,000 new jobs and generate $200 billion in revenue.

The federal government estimates about 90 billion barrels of oil have yet to be discovered in U.S. territorial waters.

Energy policies under President Donald Trump have been decidedly pro-oil. His Interior Department, meanwhile, has moved to shrink national monuments and recently backed out of a transparency initiative meant to monitor oil and gas revenue.

Apart from expanding access to drillers, the ASTRO Act would recombine the Bureau of Ocean Energy Management with the Bureau of Safety and Environmental Enforcement, which former BOEM Director Michael Bromwich said was "a profoundly bad idea."

The BSEE was set up in response to failures with the former federal Minerals Management Service in the Deepwater Horizon oil spill in the Gulf of Mexico in 2010.

https://www.upi.com/Energy-News/2017/11/07/House-takes-up-offshore-drilling-overhaul/1451510052366/?utm_source=sec&utm_campaign=sl&utm_medium=6

Canada’s Whitecap Resources Inc and at least three other companies have submitted final-round bids for Cenovus Energy Inc’s Weyburn oil facility in a deal that could fetch about C$1 billion ($782 million), people familiar with the situation said on Tuesday.

NAL Resources Management Ltd, a unit of insurer Manulife Financial Corp, Cona Resources Ltd and Spartan Energy Corp are among other suitors to place final bids, the people added, declining to be named as the matter is not yet public.

Whitecap is the front runner for the asset, one of the people said.

Cenovus has been selling assets to pay down debt used to fund its C$16.8 billion acquisition of some ConocoPhillips assets earlier this year. The Weyburn sale would bring Cenovus’ asset sale proceeds to about C$4 billion compared with its target of C$4 billion to C$5 billion in asset sales.

To finance the acquisition, Whitecap is looking to raise about C$700 million through a share sale and fund the rest through debt, the people said.

Whitecap shares closed down 1.5 percent on Tuesday. Cenovus shares, which were trading down 0.4 percent before the Reuters story, closed up 0.4 percent.

Cenovus spokeswoman Sonja Franklin declined to comment. Whitecap, NAL, Cona and Spartan did not immediately respond to requests from Reuters seeking comment.

Located in southern Saskatchewan, the Weyburn enhanced oil recovery facility uses carbon dioxide to boost crude output. Cenovus owns a 62 percent working interest in the project and operates the overall facility on behalf of 24 partners, according to its website.

Weyburn was expected to be attractive because of its light oil output and low decline, long-life characteristics. Cenovus previously said it expected to sell Weyburn by the end of the year.

Investors have been closely watching Cenovus’ asset sales process as the ConocoPhillips deal attracted the irk of shareholders and eventually led to Cenovus’ naming Alex Pourbaix, a former executive at TransCanada Corp, as its chief executive officer, replacing Brian Ferguson, who led the debt-fueled acquisition of ConocoPhillips assets.

Cenovus so far has sold assets in Palliser, Pelican Lake and Suffield for a combined value of C$2.8 billion. The company may also sell a portion of its Deep Basin business and is talking to potential buyers, the people said.

http://www.reuters.com/article/cenovus-energy-divestiture/update-1-whitecap-among-final-round-bidders-for-cenovus-weyburn-asset-sources-idUSL1N1ND1TF

ConocoPhillips aims to spend $5.5 billion/year for rest of decade

ConocoPhillips, the largest U.S. independent oil and natural gas producer, said on Wednesday it would spend $5.5 billion annually for the rest of the decade on capital projects as long as oil prices CLc1 stay above $50 per barrel.

The Houston-based company also said it expects to pay off more than $4.6 billion of debt by 2020, reducing its debt load to $15 billion. Continuing a theme of focusing on profits and not production, ConocoPhillips said it would generate a 20 percent cash return on capital employed by the end of the decade.

http://www.reuters.com/article/us-conocophillips-meeting/conocophillips-aims-to-spend-5-5-billion-year-for-rest-of-decade-idUSKBN1D81JQ

Canadian oil and gas producer Encana Corp’s profit fell 7.3 percent in the third quarter, hurt by lower oil and gas production.

The Calgary-based company said on Wednesday its net profit slipped to $294 million or 30 cents per share in the quarter ended Sept. 30, from $317 million or 37 cents per share, a year earlier.

Total oil and gas production fell to 284,000 barrels of oil equivalent per day (boe/d) from 338,000 boe/d a year ago, Encana said.

http://www.reuters.com/article/us-encana-results/encanas-profit-slips-7-percent-as-production-falls-idUSKBN1D81E0

Though constrained somewhat by hurricanes, U.S. shale oil producer Continental Resources said production should finish out the year on a high note.

Full production during the third quarter for Continental was impacted negatively by Hurricane Harvey, which impacted output from the shale reservoirs in Oklahoma. A wet season in North Dakota, meanwhile, handicapped production at the Bakken oil reservoir.

Nevertheless, the company said its third quarter production was roughly 243,000 barrels of oil equivalent per day, a 7 percent increase from the second quarter. Crude oil production, which accounts for more than half of total output, was up 12 percent from the second quarter.

In announcing its results for the third quarter, Continental said it expected even more gains as it finishes out a year when oil prices posted strong gains, after substantial weakness last year. Fourth quarter production should be at least 14 percent higher than the third quarter.

Most of Continental's production came from the Bakken oil reservoir, where production increased 15 percent.

"Continental's operations continue to become more capital efficient each quarter, allowing us to sustain our low-cost advantage," Chairman and CEO Harold Hamm said in a statement.

Hamm added that, compared with fourth quarter 2016, output by the end of the year could be as much as 38 percent higher, which he said would lead to positive growth next year.

Higher production, however, could put a strain on the momentum in crude oil prices, which hit two-year highs in recent trading sessions. Strong production from the United States is countering the impact of an agreement by the Organization of Petroleum Exporting Countries to balance an oversupplied market with coordinated production cuts.

Apart from strong production, more U.S. oil is making its way to the open market. Continental last month sold 1 million barrels of oil from the Bakken shale basin to a Houston-based trading company for delivery to China.

Continental reported revenue during the third quarter of $726.7 million. Income of $10.6 million was in line with consensus. Results were posted late Tuesday.

https://www.upi.com/Energy-News/2017/11/08/More-shale-oil-production-expected-Continental-Resources-says/9591510140238/?utm_source=sec&utm_campaign=sl&utm_medium=7

Japan’s Inpex remains on track to start production at its Ichthys liquefied natural gas (LNG) project in Australia at the end of March next year.

Speaking to reporters, the company’s senior managing executive officer, Masahiro Murayama said that peak production will be reached over the period of two years, following the start of production, Reuters reports.

Murayama said that the full-scale production would be achieved through a gradual increase in utilization rates through testing.

The Ichthys LNG project is expected to produce up to 8.9 million tons of LNG per annum and 1.65 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.

The project’s two offshore facilities, the central processing facility, Ichthys Explorer and the floating production, storage and offloading facility (FPSO), Ichthys Venturer, have been moored at their respective locations in the Ichthys field, 220 kilometers off the north coast of Western Australia.

Initially, the project was set for start-up in the third quarter of this year, however, earlier this year the company revised its plans and said that the production from the Ichthys LNG project will start before the end of the current fiscal year, ending March 31, 2018, following the installation and commissioning of the CPF and the FPSO.

Despite the delays, Inpex expects minimal cost overruns without any material impact on the project.

The project is a joint venture between Inpex, major partner Total, Taiwan’s CPC Corporation and the Australian subsidiaries of Tokyo Gas, Osaka Gas, Kansai Electric, Chubu Electric Power and Toho Gas.

http://www.lngworldnews.com/ichthys-lng-on-schedule-for-march-2018-kick-off/

                                           Last Week  Week Before  Last Year

Domestic Production '000..... 9,620            9,553           8,692

Alaska ..................................... 509               507              517

Lower 48 ............................... 9,111            9,046          8,175

Exports .................................... 869            2,133             410

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

U.S. crude oil refinery inputs averaged 16.3 million barrels per day during the week ending November 3, 2017, 290,000 barrels per day more than the previous week’s average. Refineries operated at 89.6% of their operable capacity last week. Gasoline production decreased last week, averaging 10.2 million barrels per day. Distillate fuel production increased last week, averaging 5.2 million barrels per day.

U.S. crude oil imports averaged about 7.4 million barrels per day last week, down by 194,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 7.6 million barrels per day, 0.6% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 405,000 barrels per day. Distillate fuel imports averaged 86,000 barrels per day

last week. U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 2.2 million barrels from the previous week. At 457.1 million barrels, U.S. crude oil inventories are in the upper half of the average range for this time of year. Total motor gasoline inventories decreased 3.3 million barrels last week, and are in the lower half of the average range. Finished gasoline inventories increased, but blending components inventories decreased last week. Distillate fuel inventories decreased by 3.4 million barrels last week and are in the lower half of the average range for this time of year. Propane/propylene inventories decreased by 1.1 million barrels last week, and are in the lower half of the average range. Total commercial petroleum inventories decreased by 9.1 million barrels last week.

Total products supplied over the last four-week period averaged over 19.9 million barrels per day, down by 0.8% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.3 million barrels per day, up by 3.0% from the same period last year. Distillate fuel product supplied averaged 3.9 million barrels per day over the last four weeks, down by 2.9% from the same period last year. Jet fuel product supplied is up 2.6% compared to the same four-week period last year.

Cushing up 800,000 bbls

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

Distressed debt investors in U.S. oil and gas companies are turning into activist shareholders and pushing for more deals in the sector to boost the value of energy holdings they snapped up during the oil market slump.

Hedge funds, such as Fir Tree Partners and Strategic Value Partners, bought debt of many U.S. energy firms for pennies on the dollar as oil tumbled more than 70 percent in late 2014 and 2015 and later swapped it for shares in bankruptcy proceedings.

But rather than cash out by selling the shares once the revived companies returned to the stock market as they would typically do, the funds kept their stakes because tepid crude price recovery has held down energy firms’ valuations.

Now with oil prices at their highest since July 2015, hedge funds are seizing the moment and trying to convince companies to sell assets or consider tie-ups to squeeze more value from their investments.

For example, Ultra Petroleum Corp and Midstates Petroleum said they would pursue deals this year as a result of pressure from distressed debt funds.

Over the course of 2015 and 2016, 96 U.S. oil and gas companies filed for bankruptcy, according to law firm Haynes and Boone. At least 12 re-listed on the stock market with distressed debt hedge funds as their shareholders, according to a Reuters review of bankruptcy court filings and shareholder data. (Graphic:tmsnrt.rs/2zbKieM)

With its shares down as much as 45 percent since its initial public offering in April, Ultra Petroleum, for example, said in September it would explore ways to boost its stock value together with Fir Tree, including hiring an investment bank to sell assets.

CALL FOR ACTION

Fir Tree also joined Q Investments in September in calling for Jones Energy to change course, including the possible sale of the company. Jones survived the worst of the oil slump, but its shares are down around 70 percent this year.

“When the share price breaks $1, it shows you need to act quickly,” said Scott McCarty, partner at Q Investments.

Fir Tree, which manages around $9.4 billion, is the most consistent presence in these reorganized energy companies.

David Proman, its co-head of restructuring, said the fund was pushing firms to pursue deals because the stock market did not value its holdings at fair prices.

He noted that in several cases shares of the reorganized company were trading at levels which valued it below what the bond prices indicated before and during the bankruptcy.

With many firms, funds want them to focus on key basins to reduce costs of having equipment and staff spread widely. Funds are hoping the spun-off oil and gas patches will attract interest from oil majors and large independents, which need to replenish reserves after the slump, or other operators focused on that particular geography.

With shareholder meetings due early in 2018, calls for management boards to take action may intensify before the end of this year.

“There are a number of mismanaged oil and gas companies and a lot of potential activism targets trading well below their peers,” said Kai Haakon Liekefett, head of law firm Vinson & Elkins’ team that advises boards on dealing with activist shareholders.

Such campaigns could help bring about more deals in the U.S. oil and gas sector after activity slowed this year because most companies shunned large, transformative deals due to uncertain oil price outlook. Just under $114 billion of mergers and acquisitions had been announced by Oct. 25, down 7.4 percent from a year ago, according to Thomson Reuters data.

LACK OF EXPERIENCE

Taking a leaf out of activist investors’ book, hedge funds are calling for representation on boards of directors, as Strategic Value Partners did on Sept. 13 with Penn Virginia Corp.

Such demands mark a further departure from funds’ short-term investment approach, given funds must agree not to sell shares in the open market as long as their representatives sit on the board.

To be sure, calls for board seats and other actions can face resistance and distressed debt funds often lack experience in battling over corporate strategy and canvassing other shareholders.

Recruiters say some funds have started looking for shareholder activism veterans to bring in that expertise.

For example, D.E. Shaw & Co, a $40 billion hedge fund, hired Quentin Koffey in June from Elliott Management Corp, one of the world’s most prominent activist hedge funds.

“If (funds) don’t have the skills, maybe they will look to partner with someone who does, or they will seek to learn it through bankers and lawyers and by bringing in the right people,” said Ele Klein, co-chair of the global shareholder activism group at law firm Schulte Roth & Zabel LLP.

http://www.reuters.com/article/us-energy-debt-activism/distressed-debt-funds-turn-activist-to-rescue-u-s-energy-bets-idUSKBN1D90KK

French oil giant Total has signed an agreement with Engie to acquire its portfolio of upstream liquefied natural gas (LNG) assets for $1.49 billion to become the second largest global LNG player

This portfolio includes participating interests in liquefaction plants, notably the interest in the Cameron LNG project in the US, long term LNG sales and purchase agreements, an LNG tanker fleet as well as access to regasification capacities in Europe.

Additional payments of up to $550 million could be payable by Total in case of an improvement in the oil markets in the coming years.

“The acquisition of Engie’s upstream LNG business enables Total to accelerate the implementation of its strategy to integrate along the full gas value chain, in an LNG market growing strongly at 5 per cent to 6 per cent per year. The combination of these two complementary portfolios will allow the Group to manage an overall volume of around 40 million tonnes of LNG per year by 2020, making Total the second largest global player among the majors with a worldwide market share of 10 per cent”, commented Patrick Pouyanné, chairman & chief Executive Officer of Total.

With the equity stake in the Cameron LNG project, Total will also become an integrated player in the US LNG market, where the Group is already a gas producer”

The deal is expected to close by mid 2018.

Following the transaction, Total will take over the teams in charge of the LNG activities at Engie, which represents around 180 employees. In addition Total and Engie agreed to cooperate to promote the use of biogas and renewable hydrogen, with Engie becoming Total's priority supplier in this field.

https://www.pipelineme.com/regionalinternational-news/international-news/2017/november/total-buys-engie-s-lng-business-for-us-149-bln

Rapid advances in data, analytics, 3D printing, smart appliances, and a range of other digital technologies will revolutionize the energy sector, making the world more connected, intelligent, efficient, reliable, and sustainable, according to a new report from the IEA. The agency estimates that more than one billion households and 11 billion smart appliances could potentially participate in interconnected electricity systems by 2040. This development will radically change how energy is produced and consumed. “Digitalization is blurring the lines between supply and demand,” said IEA Executive Director Fatih Birol. “The electricity sector and smart grids are at the center of this transformation, but ultimately all sectors across both energy supply and demand—households, transport and industry—will be affected.”

But the brave new world of energy digitalization will include some downsides. Risks related to privacy, security, and the disruption that comes from unseating incumbent technologies are all cause for concern.

Digitalization in oil and gas

Oil and gas drilling is already highly digitalized. However, the industry is constantly innovating, particularly as it tries to cut costs and adapt to an increasingly uncertain and volatile market.

Big Data will become a regular fixture in the oil and gas industry in the future, greatly enhancing drilling techniques and strategies. Being able to crunch and process massive volumes of seismic data, for example, can accelerate the lead times for new projects. Comparing geological data to well performances helps companies find where to drill and how to drill. New advanced analytics takes into account all of these variables and allows drillers to optimize each project, without having to resort to trial and error, which has how companies have traditionally operated.

Big Data will became a regular fixture in the oil and gas industry in the future, greatly enhancing drilling techniques and strategies.

Other technologies will also become more abundant over time that will dramatically change the oil and gas industry. Miniaturized sensors and fiber optic sensors will help increase the volume of oil and gas that can be recovered from a reservoir. Automated drilling rigs, subsea robots, and drones will take on a greater role going forward.

Many of these technologies are already making inroads in the industry. A year ago, GE unveiled a new helicopter drone that could detect methane leaking from a drilling site in the Fayetteville Shale in Arkansas. The drone could replace a worker that has to manually walk around the site using an infrared camera to detect any methane leakage. In theory, the use of a drone will make inspection safer, faster, and cheaper.

The industry is increasingly using “smart pigs,” or robots that travel through pipelines to inspect them and detect corrosion.

Another example is the increasing use of “smart pigs,” or robots that travel through pipelines to inspect them and detect corrosion. Smart pigs are becoming increasingly adept at finding problems, and crucially, advancements in data analysts are allowing for the interpretation of the massive volumes of data the pigs produce when passing through a pipeline. In the past, the results would take months to analyze, but that time has been drastically reduced. Moreover, predictive analytics would allow a company to use that data to discover problems and proactively respond before the situation got out of control.

Put it all together and the changes could be considerable. The IEA estimates that digital technologies may lower oil and gas production costs by 10 to 20 percent. As a result, technically recoverable oil and gas reserves could climb by as much as 5 percent globally, with the largest gains from shale gas, the IEA says.

Implications for oil demand

Oil producers will see enormous benefits from digitalization, while at the same time steady innovation in the transportation sector could erode consumer demand petroleum. For example, airlines are using data analytics to optimize travel routes and allow pilots to make decisions during flights, which will cut down on fuel consumption. The same is true in the maritime industry, making global trade more efficient.

Road transport will see the most “revolutionary changes from digitalization,” the IEA argues, which could “fundamentally transform how people and goods are moved.” New technologies will allow passenger vehicles to be automated, connected, electric, and shared (ACES).

Road transport will see the most “revolutionary changes from digitalization,” the IEA argues.

The ramifications for crude oil demand are highly uncertain, and depend very much on the rate of innovation, policy intervention, and consumer behavior. The most bullish long-term forecast for ACES technology adoption would cut energy consumption in the transportation sector by half. One example the IEA cites is the potential for digital solutions in trucking and logistics—including GPS, real-time traffic data, on-board monitoring of driving techniques, and data sharing to reduce the volume of trips taken—could reduce oil consumption for road freight by 20 to 25 percent.

More vulnerabilities

There are undoubtedly a long list of benefits from the increased digitalization of the energy system, but it also brings new challenges. With cars, planes, ships and power plants all connected, the threat of cyberattacks may rise.

There have been several high-profile incidents in the last few years. The Shamoon virus infected 30,000 computers belonging to Saudi Aramco in 2012, destroying around 85 percent of the company’s computer hardware. Another notable incident was the infamous Stuxnet virus, which destroyed centrifuges at an Iranian nuclear facility in 2010. More recently, a phishing attack targeted several U.S. utilities, although power plants and the electricity grid were unaffected. The list of targets, and the potential damage, could increase significantly over time as more critical assets become connected online.

Another concern about the rapid pace of digitalization in the energy sector is privacy. This tension between innovation and efficiency on the one hand and privacy on the other will define the rapid changes that will take place in the digitalization space. Overall, the benefits could be profound, but policymakers and industry will have to resolve the array of new challenges that come with the digitalization of the energy industry.

http://energyfuse.org/energy-digitalization-bring-significant-rewards-also-risks/

Noble Energy has agreed to sell off thousands of acres in Colorado's DJ Basin for $608 million, jettisoning two areas it hadn't planned to develop for several years.

The Houston oil company will sell 30,200 net acres in Weld County, in so-called non-core areas where it pumps only 4,100 barrels of oil equivalent a day.

About half of the acreage is in an area it named Greely Crescent, and the other half is in the so-called Bronco area of basin. Only 20 percent of the hydrocarbons produced in the area are oil.

It said Wednesday it would close part of the deal, its sale of non-operated acreage, by the end of the year, and it plans to close the sale of land it operates by mid-2018. Noble CEO Gary Willingham said the company would continue to drill in the northern and eastern parts of the DJ Basin.

"This is where we have a deep inventory of long lateral drilling opportunities in an oilier part of the basin," Willingham said.

Noble will have some 335,000 net acres in the DJ Basin after the deal closes next year

http://www.chron.com/business/energy/article/Noble-to-sell-thousands-of-acres-in-Colorado-oil-12342438.php

In a word, booming describes the status of the Guyana offshore oil and gas exploration scene. The 6.6 million acre Stabroek Block, located in the Guyana Basin, is home to five exciting, new discoveries since 2015. Beginning with Liza, then continuing with Liza Deep, Payara, Snoek, and Turbot, the basin’s estimated recoverable oil reserves sits near 2.5 billion barrels. The Payara, Snoek, and Turbot discoveries in 2017 contain approximately one billion barrels of recoverable oil. Due to continued successful drilling by ExxonMobil (XOM), these discoveries appear to be only the beginning of a long-term, prosperous time for those investing in the Stabroek Block, with less than 25% of the block explored.

The most recent discovery of the Turbot field, approximately 50 km southeast of Liza, further displays the significance of the undeveloped area. Initial estimates place the discovery over 500 million barrels (MMbbl) of recoverable oil. To put in perspective, the average recoverable oil for producing fields discovered in the United States Gulf of Mexico (USGoM) between 2000 and 2015 is only 15.7 MMbbl. This is according to Bureau of Ocean Energy Management (BOEM) data. While this highlights the potential of the Stabroek Block, it also demonstrates the need for investment in infrastructure in Guyana (Image 1). Small fields can come onstream in an area with an abundance of existing production facilities, such as the USGoM (Image 2), however Guyana lacks pipelines, terminals, refineries, and other necessary equipment to make marginal developments possible.

Figure 1: Stranded assets off the coast of Guyana

Figure 2: Abundant infrastructure in U.S. Gulf of Mexico

The fact that XOM plans to bring the Stabroek Block onstream in 2020, beginning with the Liza field, shows these continued success stories are resulting in large investments and high hopes, despite the lack of existing infrastructure. The large cash exposure would not be possible in the area without the massive reserve estimates from sustained discoveries like Turbot.

In fact, XOM decided to slightly offset this cash exposure by utilizing a leased FPSO. Phase 1 of the Liza asset is set to be developed using a lease capitalization method, which reduces risk associated with opening production from the play. According to IHS Markit calculations, using a leased FPSO for phase 1 of the Liza development increases the asset’s NPV by approximately US$700 million. Breakeven oil price drops from US$38/bbl to US$36/bbl when switching from an owned to leased FPSO. Further lease options may be used for following developments, however it is assumed, once the area is de-risked, FPSO purchases will begin. The four assets within the Stabroek basin are favorable from an economic perspective (See figure 3).

Figure 3: Stabroek Block asset economics

Development of the fields in the Stabroek block could end the country’s energy dependence. With an NOC to be established some time in 2018, according to the natural resource minister, production and developments could be more regulated. However, due to Guyana being one of the poorest countries in Latin America, we expect regulations to be industry friendly in order to encourage more investment from operators like XOM. In addition, the current fiscal terms in place are very favorable to the operators/partners, further driving investments in the region. The Ranger and Skipjack prospects are set to be drilled next, further proving that XOM is confident and ready to drive development in the area, while minimizing the associated risks with being the play opener.

http://blog.ihs.com/how-activity-in-the-guyana-mini-basin-is-booming-with-five-exciting-discoveries-since-2015

Asian condensate buyers have lots to consider when setting up their feedstock procurement plans for 2018, as Australia's new ultra-light crude stream is expected to spur intense competition among producers in Southeast Asia and Oceania, while a potential decline in Iranian exports next year could open doors for various arbitrage supplies, market sources said Wednesday.

Traders especially noted that regional refiners and petrochemical companies may have to brace themselves for some price turbulence next year, and the supply and demand balance in the Asian condensate market could swing either way, as Oceania will likely see a boost in production, though supply is expected to tighten in the Middle East.

"Everyone's been talking about US [crude and condensate this year] but those are just opportunistic deals, nothing steady and long term ... new [condensate] production in Australia and [a likely fall in] Iranian exports will be the main market mover next year," said a condensate trader at a Japanese company.

Asian end-users will likely keep a close eye on Australia's new Ichthys condensate, as the naphtha-rich grade could make its debut sale in the Asian spot market within the first half of next year, posing a direct competition to ultra-light crude producers around the region, traders said.

Project operator Inpex said earlier this year that first production of Ichthys condensate is scheduled to commence towards the end of March 2018, and the company is expecting to see the output of the ultra-light crude to reach 100,000 b/d at peak.

"Ichthys would easily rival NWS [North West Shelf] condensate," said a Northeast Asian condensate trader.

ICHTHYS TO RIVAL REGIONAL GRADES

Price differentials for various Southeast Asia and Oceania condensate grades may come under pressure in 2018 as monthly Australian ultra-light crude supply in the spot market could almost double when the new Ichthys production come on stream according to schedule.

Although the quality of Ichthys condensate remains in question with no official assay of the grade made available yet, traders said the peak output target of 100,000 b/d would be enough to grab plenty of Asian buyer interest.

The 100,000 b/d peak output target would roughly equate to around four to five 650,000-barrel cargoes for sale every month, market sources said.

In comparison, around three to four 650,000-barrel cargoes of Australia's flagship North West Shelf condensate and a 300,000-barrel parcel of either Pluto or Laminaria condensate are offered in the Asian spot market in a typical trading cycle. NWS is currently the most liquid and actively traded condensate grade in the regional spot market.

Indonesia's Pertamina, the biggest customer of NWS condensate over the past two years, has been in discussion with Inpex to assess the suitability of the new Ichthys condensate, for its Trans Pacific Petrochemical Indotama plant in Tuban, a company source told S&P Global Platts.

The source indicated that Pertamina has no immediate plans to tie up any supply contracts until the complete assay is available, but the company is hopeful that the new grade would help trim regional ultra-light crude prices, while reducing its hefty dependence on NWS condensate.

"We are still not sure about the mercury content but [Ichthys] offers very good chance to diversify ... [100,000 b/d] volume is massive for a regional grade so it will spark competition [among regional sellers] too," the source said.

"It's too early to ask for a sample to test because only one or two of the many production wells are active at the moment ... We are very hopeful that [when Ichthys reaches peak production next year,] it will put pressure on many regional condensate prices," said a trading manager at a South Korean refining company.

Most, if not all, regional ultra-light grades have commanded healthy premiums over the Platts Dated Brent price benchmark so far this year.

Among recent trade deals, a 600,000-barrel cargo of East Timorese Bayu Undan condensate for loading in October was said to have traded at a premium of around $1/b to Platts Dated Brent, while Petronas recently sold a 250,000-barrel cargo of Malaysian Cakerawala condensate for loading over December 21-30 at a premium of around $2.80/b.

In Australia, BHP and Woodside Petroleum each sold a 650,000-barrel cargo of NWS condensate for loading in December at premiums of $2.70-$3.30/b on a FOB basis, trade sources said.

LESS SOUTH PARS CONDENSATE

Meanwhile, Asian condensate buyers have expressed some concerns over a possible decline in Iranian condensate exports in 2018 amid Tehran's fast growing domestic refining capacity.

Any significant drop in term contract volumes for South Pars condensate next year could trigger a rally in the broader Middle Eastern ultra-light crude complex, while various Asian refiners and petrochemical producers may actively venture into Europe and Africa for extra supplies, market sources said.

South Korea's Hanwha Total Petrochemical for one, aims to secure at least around 100,000 b/d of Iranian South Pars condensate for next year, a company source with knowledge of the matter told Platts.

Hanwha Total, one of the biggest Iranian condensate buyers, remains hopeful that it could secure the desired amount, but anything short of 100,000 b/d could force the company to actively seek other options within and outside the Middle East, especially to accommodate its increased refining capacity, the source said.

The South Korean firm said in July that it has increased the capacity of its condensate splitter at Daesan to 180,000 b/d from 150,000 b/d.

"South Pars is one of the most economical condensate grades, almost always at least $1/b cheaper than [Qatar's] DFC condensate ... if there's not enough [South Pars supply next year], Qatari grades might start to rally and many buyers would have to look outside for cheaper ones," the source said.

Regional traders point to several non-regional grades including Equatorial Guinea's Alen and Alba condensate, Libya's Mellitah condensate as well as Norway's Snohvit and Orman Lange as potential candidates that could actively find outlets in Asia in the event of significant reduction in Iranian South Pars exports next year.

"Tighter [condensate] supply [in the Middle East] will push prices sharply up ... [this could subsequently encourage Asian] buyers to seek barrels from both their traditional and non-traditional arbitrage sources on regular basis," said a Singapore-based sweet crude trader.

Two European trading firms, Glencore and Lord Energy have been the main suppliers of Alen and Mellitah condensate respectively, to Asia this year so far and any drop in Iranian exports would likely boost their arbitrage sales, sources close to the companies said.

In September, a senior official at state-run National Iranian Oil Company has said the country's domestic ultra-light crude requirement would rise rapidly as the remaining two condensate splitters at the new Persian Gulf Star refinery complex are planned to come online next year.

Iran has been exporting as much as 700,000 b/d of ultra-light crude up until recently but domestic consumption next year could reach about 360,000 b/d from around 120,000 b/d currently, NIOC director of international affairs Saeid Khoshrou said previously.

https://www.platts.com/latest-news/oil/singapore/analysis-australia-iran-could-dictate-2018-asia-27887375

Australia’s Santos Ltd expects to hold its gas output roughly steady over the next several years, with growth to kick off in 2023 from projects in northern Australia and Papua New Guinea.

Chief Executive Kevin Gallagher sought to reassure Santos investors on Thursday that the company has halted a decline in its natural gas output from its ageing Cooper Basin field and is on track to cut net debt to $2 billion by the end of 2019.

“We acknowledge that there’s still more to go, but significant progress has been made on the journey so far,” he told investors at a briefing.

“We’ve now got a core portfolio that has no decline between now and beyond 2025,” he said, referring to the company’s five main holdings - Gladstone liquefied natural gas (LNG), Narrabri, and assets in the Cooper Basin, northern Australia and Papua New Guinea.

Santos expects production in 2018 to be roughly in line with this year at between 55 million and 60 million barrels of oil equivalent (mmboe).

However investors sent Santos shares down 3 percent, after the company forecast its sales - which include some third party gas - would drop by about 7 percent to between 72 and 78 mmboe in 2018, partly due to declining output from non-core fields in Indonesia and Vietnam.

At the same time it plans to increase capital spending by about 17 percent to between $825 million and $875 million.

But Gallagher was upbeat as Australia’s no.2 independent gas producer has slashed production costs by a third to the point where it breaks even at an oil price of $32 a barrel, well below current prices around $60.

If oil prices remain at these levels through 2018, Santos could be in a position to revive its dividend, scrapped in 2016, or return cash to shareholders some other way by the end of next year, he said.

“It’ll be a great problem to have in 2018 to be talking about that again,” Gallagher said, adding that the company will also be able to fund growth projects that it expects to sign off on in late 2019 or 2020.

There would be “no big step-out” acquisitions, but Santos would look at deals around its five core assets.

That could include increasing its stake in Darwin LNG to match Santos’ 25 percent interest in the Barossa-Caldita gas field, which is likely to feed the LNG plant from 2023.

http://www.reuters.com/article/santos-strategy/update-2-australias-santos-growth-to-come-from-2023-onward-idUSL3N1NE6LO

Iraq’s Kurdistan has made its full monthly payment of around $100 million to oil producers working on its territory, despite a big drop in oil exports amid a political crisis roiling the semi-autonomous region.

A source close to the Kurdistan regional government told Reuters that full monthly payments had been made to companies such as Genel, DNO, Gulf Keystone, Gazprom and Taqa.

Kurdistan’s oil exports have dropped to just around 220,000 barrels per day from the usual 600,000 bpd over the past month after some major fields have been taken over by Iraqi forces, causing a drop in production and a lack of clarity on who owns the barrels.

http://www.reuters.com/article/us-iraq-kurdistan-oil/iraqs-kurdistan-makes-100-million-monthly-payment-to-oil-producers-despite-crisis-source-idUSKBN1D91UN

The soaring diesel market has taken a turn for the worse. That could be bad news for oil bulls who amassed record bets on a rally in crude.

With demand for the fuel accelerating in September after a hurricaneknocked out a swath of U.S. refining and fires eliminated processing in Europe’s hub, diesel was credited with underpinning a rally in crude. Brent jumped above $60 a barrel last month and is still on an upward trajectory. But while those refinery issues are normalizing -- and diesel is weakening -- there’s been little let-up in the rally in crude futures. They reached a more than two-year high of $64.65 a barrel on Nov. 7, and remain close to that.

“This will counter the recent support to crude,” Alan Gelder, vice-president of refining, chemicals and oil markets at Wood Mackenzie, said of signs the diesel market is weaker than expected. “Particularly if demand growth turns out to be disappointing” given the importance of diesel as a source of consumption during winter months.

In September, prices for diesel for immediate supply surged relative to later months. ICE gasoil, Europe’s main diesel contract, turned to a structure called backwardation, indicating a more pressing need for supply. Fuel flows to Europe from the Gulf of Mexico all but dried up in the wake of Hurricane Harvey, tanker tracking data compiled by Bloomberg show. The opposite price pattern -- contango -- had largely prevailed since early 2015.

What happens in diesel matters for crude. The fuel is central to the pricing of other so-called distillates that also include jet fuel and heating oil, which together, account for over one third of global oil consumption, according to data from BP Plc.

Speculators have piled back into the oil market with record bullish bets. The net-long position in Brent crude futures and options was the equivalent of 530 million barrels last week, according to ICE Futures Europe data, with more than 10 long positions for each short. Money managers have also been diving into gasoil, where at one point last month there were almost 20 longs for every short, the highest ratio in four years. That bullishness has subsequently faded to 12.6.

Facts Global Energy attributes the strength in distillates mainly to Germany, Europe’s largest market for heating oil, where purchases were strong into July. “The early buying spree has led to full tanks now, which, in combination with a warm winter, could hamper oil demand over the next months,” said Cuneyt Kazokoglu, an analyst at Facts Global Energy.

Still, the dip in diesel could be short-lived. Energy Aspects Ltd., a London-based consultant, says that the weakening reflects the market digesting supplies that were removed from storage. Likewise, Indian refineries delayed routine maintenance until the first quarter of next year, meaning there will likely be reduced supply then. There will also be work on refineries in the Middle East early next year that will further tighten the market, Energy Aspects said.

For now, though, diesel isn’t looking as strong as it did a few weeks ago. The most liquid time spread -- December and January -- is now in a contango of $1.50 a metric ton. It was backwardated by $4.75 as recently as Sept. 21. The fuel’s premium to crude has weakened to just over $12 a barrel from $15.67 in late September.

That weakening is “a bearish flag for the strong demand-growth theme” in crude, said Olivier Jakob, an analyst at Petromatrix GmbH based near Zug, Switzerland. “It is one part of the barrel that is not going in the same direction that the flat price is going.”

https://www.bloomberg.com/news/articles/2017-11-09/diesel-dip-gives-record-bullish-oil-traders-pause-for-thought

The U.S. export boom continues apace. And not only from crude exports, which clambered above 2 million barrels per day in recent weeks, but from the product piece of the pie too. Joining rising gasoline and distillate exports from the U.S. has been LPG. And not just propane or butane, but ethane as well - as our ClipperData illustrate below.

With the start up of Enterprise' Morgan's Point terminal on the Gulf Coast last year, as well as Sunoco's Marcus Hook terminal on the East Coast, ethane exports have gradually risen from averaging just under 30,000 bpd in Q3 of last year to nearly 140,000 bpd in Q3 just passed.

Ethane production in the U.S is expected to average ~1.45 million bpd this year, up from 1.25mn bpd last year. It is set to maintain its upward trajectory in the coming years, driven by higher domestic consumption (from the petrochemical industry) and increasing demand for exports.

Marcus Hook has export capacity of 35,000 bpd, while Morgan's Point has capacity of 200,000 bpd. The export trade is going so well that Enterprise is planning a second ethane export terminal on the Gulf Coast. India has been the leading destination for U.S. ethane exports this year, followed by the U.K., Norway and Sweden.

Propane exports have been on a similar upward trajectory. After averaging just shy of 600,000 bpd in 2015, they rose to 770,000 bpd in 2016, and are currently at 970,000 bpd for the first ten months of the year.  

East Asia is the leading destination for U.S. propane, accounting for over 40 percent of exports, with Japan, South Korea and China being the top three recipients of U.S. propane globally. Mexico is fourth. U.S. propane exports have averaged above 1 million barrels per day in five out of ten months this year.

Gasoline and middle distillate exports join LPG in continuing to push higher. After a blip in September due to hurricane activity, exports of both are on the rise again, pushing to a new combined record. Even with the September blip, exports of the two have averaged over 2.3 million bpd this year, after 2.2mn bpd in 2016, and 2.1mn bpd in 2015.

As domestic demand ticks higher along with exports, and as imports into the U.S. East Coast drop, total U.S. gasoline and distillate inventories are falling - despite a record year of refinery runs so far in 2017.

Gasoline inventories have fallen by 26 million barrels since the start of the year, dropping 11 percent, while distillate inventories have now dropped by 36 million barrels, down 22 percent.  These two retracements make oil's inventory drop of 5 percent drop seem less significant in comparison.

http://blog.clipperdata.com/booming-us-product-exports

The amount of oil stored on tankers around Singapore has dropped sharply in the last months, the latest indication that OPEC-led supply cuts are successfully tightening crude markets even as U.S. exports have soared.

Shipping data in Thomson Reuters Eikon shows around 15 super-tankers are currently filled with oil in waters off Singapore and western Malaysia, storing around 30 million barrels of crude. That is half the number of ships in June and down from 40 tankers holding surplus fuel in mid-2017.

The drop in floating storage around Asia’s main oil-trading hubs comes in the wake of voluntary production cuts led by the Organization of the Petroleum Exporting Countries (OPEC) and Russia as they look to choke off a supply overhang that has dogged markets for years.

“There are less incentives for traders to hold crude given rising crude oil prices and premiums. So to some extent, the OPEC cuts have worked,” said Eng Hian, head of trading at AgriTrade Energy in Singapore, which trades crude and operates tankers used for storage.

Brent crude futures are up more than 40 percent since July to almost $64 per barrel. Also, the Brent forward curve shows contracts for future delivery are cheaper than spot supplies, a condition known as backwardation which makes it unattractive to store oil.

“The (backwardation) structure has flushed out oil in storage,” Eng Hian said.

MISSION ACCOMPLISHED?

The OPEC-led cuts were initially slated to last for the first half of 2017, but have since been extended until March next year as some participants took time to comply with the curbs and as U.S. crude imports jumped.

Tighter supplies are also evident in physical oil markets.

Saudi Arabia this month lifted the price for its light crude in Asia to the highest level since September, 2014, just before the glut started.

U.S. bank Goldman Sachs said this week that falling inventories were also driven by strong demand for oil.

“Strength in demand is an important force in the rebalancing of the global oil market ... It has helped the decline in excess inventories,” Goldman said in a note to clients.

Despite the tighter market, energy consultancy FGE warned this week that due to rising U.S. shale production and a potential jump in OPEC supplies after the end of its voluntary cuts, a supply glut could re-emerge.

“This may result in lower prices in 2019,” FGE said.

U.S. oil production climbed to a record of over 9.6 million barrels per day (bpd) this month, and output is set to climb further. Texas issued around 1,000 oil and gas drilling permits last month, up nearly 17 percent from the same month a year ago, according to the state’s energy regulator.

http://www.reuters.com/article/us-asia-oil-storage/sinking-feeling-asian-floating-oil-storage-declines-as-crude-market-tightens-idUSKBN1DA0D7

Saudi Arabia plans to cut crude exports by 120,000 barrels per day (bpd) in December from November, reducing allocations to all regions, a spokesman for the energy ministry told Reuters on Thursday.

Crude exports to the United States will be more than 10 percent lower than November levels, he said.

The world’s top oil exporter said it planned to ship slightly more than 7 million bpd this month, up from low levels during summer when domestic demand was at its peak.

Seasonal drops in domestic crude demand free up more oil for export during the winter months.

The Organization of the Petroleum Exporting Countries, along with other non-member oil producers led by Russia, agreed to cut output by around 1.8 million bpd from Jan. 1 this year until March 2018.

OPEC is seeking to achieve consensus among the participating countries ahead of its next meeting in Vienna on Nov. 30 on how long to extend the deal beyond March.

http://www.reuters.com/article/us-saudi-oil-exports/saudi-arabia-to-cut-crude-exports-by-120000-barrels-per-day-in-december-idUSKBN1D92KW

Saudi Aramco signed agreements on Thursday worth $4.5 billion with firms from Europe, the United States, China and the United Arab Emirates for work on a range of oil and gas development projects, mostly aimed at boosting gas production.

Saudi Aramco is pushing ahead with energy projects that it has listed as a priority to keep the world well supplied with oil while meeting increased domestic demand for gas to fuel industrial growth.

By freeing up more oil for export, gas projects will increase supplies to energy utilities and as feedstock for the petrochemical industry. Aramco has plans to double its gas output to 23 billion standard cubic feet per day.

Signing the deals at a public ceremony in Dhahran, Aramco did not give the value of each agreement.

Among the deals, Spanish engineering company Tecnicas Reunidas (TRE.MC) is to build gas compression plants for the Hawiyah and Haradh fields which will extend plateau production for both fields for the next 20 years, Aramco said.

The project will boost gas production capacity by 1.3 billion standard cubic feet per day.

In related work Italy’s Saipem (SPMI.MI) has won a deal estimated to be worth around $700 million to expand capacity at the Hawiyah gas processing plant, which is due to have a total capacity of 3.86 billion scfd by June 2021, when the new work is due to be completed.

Meanwhile, China Petroleum Pipelines has been contracted to lay 450 kilometres of gas pipelines by early 2019 to take 290 million scfd of gas from the Haradh field to the Hawiyah processing plant.

“This reflects our commitment to introducing new supplies of clean-burning natural gas. These new supplies will help reduce domestic reliance on liquid fuels for power generation, enable increased liquids exports, provide feedstock to petrochemical industries, and reduce carbon emissions,” Amin Nasser, CEO of Aramco said.

OIL CAPACITY UNCHANGED

In a separate project U.S. company Jacobs Engineering (JEC.N) has been awarded preliminary engineering and project management services agreement for a new processing plant to handle 600,000 barrels per day of heavy crude production from the giant Zuluf field in the northeast of the Gulf.

In the same area at Safaniya, Abu Dhabi-based National Petroleum Construction Co (NPCC) and U.S. group McDermott International (MDR.N) were awarded contracts for additional work on the oil field.

But despite these incremental projects the company is not aiming to increase its overall maximum sustainable production capacity, which currently stands at 12 million barrels per day, Nasser said.

“Bringing new increments will sustain the production plateau (at the fields),” he told reporters after the signing ceremony.

http://www.reuters.com/article/us-aramco-projects/saudi-aramco-signs-engineering-and-construction-deals-worth-4-5-billion-idUSKBN1D925G

Petronet LNG, India’s largest importer of liquefied natural gas, reported a 28 percent increase in its quarterly net profit, boosted by higher regasification volumes at its Dahej and Kochi terminals.

The LNG importer said its net profit after tax rose to 5.89 billion rupees ($15.4m) in the September quarter, as compared to 4.60 billion rupees in the same quarter a year before.

Shares of Petronet LNG rose as much as 5.4 percent on Thursday, their highest since October 24.

Petronet said its Dahej LNG import facility regasified record 210 trillion British thermal units in the quarter under review, operating at around 110 percent of its nameplate capacity.

These volumes rose by 14 percent over the same quarter the year before.

The company’s Kochi LNG terminal “processed the highest ever quantity” of 10 TBtu of LNG, Petronet

http://www.lngworldnews.com/petronets-profit-climbs-28-pct-on-record-lng-volumes/