A glut of North Sea oil that’s helped depress global prices and heap pressure on OPEC is poised for short-term relief after traders booked tankers to take as much as half of the region’s key oil flow to Asia.

Mercuria Energy Group Ltd. and Royal Dutch Shell Plc booked Forties crude onto tankers that typically haul 2 million barrels each for loading this month, according to lists of charters and four people involved in the market. Statoil ASA provisionally booked a ship to collect North Sea oil by Dec. 5. The combined outflow could exceed 500,000 barrels a day over an 11-day period, more than half the rate of key Brent, Forties, Oseberg and Ekofisk loadings.

“For now, it’s kind of a short-term relief,” said Olivier Jakob, managing director of Petromatrix GmbH in Zug, Switzerland, adding that there are still too many moving parts to determine when and how a global excess will be eliminated.

The bookings come at a time when insufficient demand is causing traders to store millions of barrels of North Sea oil on tankers because there’s not enough space on land. At the same time, the Organization of Petroleum Exporting Countries is working on a plan to try to eliminate a global surplus and stem a price slump. The group meets in Vienna on Nov. 30, attempting to finalize an accord it set out eight weeks ago in Algiers to trim as much as 1.5 million barrels a day from supply.

Contango Trading

North Sea oil is trading in a pattern known as contango, where a physical-market surplus pushes down immediate-month future contracts below those in later periods. That gap got so wide this month that it cost investors more than $1 a barrel to extend, or roll, bullish trades when most-immediate Brent contracts expire, from less than 50 cents earlier this year. The spread narrowed to as little as 93 cents on Wednesday, the smallest since Nov. 16, ICE Futures Europe data show.

As much as 12 million barrels of benchmark North Sea grades are now in floating storage off the U.K. coast as land sites fill up, according to ship-tracking data compiled by Bloomberg. While that puts pressure on Brent, it also makes the grade more attractive to buyers in other parts of the world.

“Now the North Sea is priced not only to go to floating storage, but also to be exported to all regions,” said Jakob.

The region next month is scheduled to load an average of 2.1 million barrels of crude a day, the most in 4 1/2 years, according to data compiled by Bloomberg. That oil may either be stored or exported. For the key Brent, Forties, Ekofisk and Oseberg grades, that flow is less than 1 million barrels a day.

Mercuria is set to load the vessel Argenta at Hound Point on Nov. 25, from where it will sail to China, the fixtures show. Shell is to load the Victory I from the same location on Nov. 29. The tanker’s destination after that is still unclear but most supertankers head to Asia once they’ve loaded North Sea barrrels.

In addition, Statoil ASA provisionally chartered the supertanker Bunga Kasturi Lima to load at the Norwegian port of Mongstad from Dec. 1-5, where it will then sail for South Korea, shipping fixtures show. If that loading proceeds, the tanker will be the first to head to Asia from Mongstad since November 2012, according to data compiled by Bloomberg.

https://www.bloomberg.com/news/articles/2016-11-23/north-sea-oil-glut-to-get-short-term-relief-as-barrels-flow-east

The ramp up we have seen in Saudi, Iraqi - and particularly - Iranian oil exports. The chart below highlights how Iranian oil exports have flowed back into the EU after the lifting of sanctions at the beginning of the year.

Iranian flows have also increased into Europe as Nigerian flows have dropped off, with West African exports rising to the U.S. East Coast as Bakken production has drifted lower and as crude by rail economics have become increasingly unfavorable. The chart below also highlights the recent increase in Libyan exports as production returns. The vast majority of Libyan oil exports head to Europe:    

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Attached Files

As the oil market anxiously awaits OPEC’s decision next week, some of the countries hardest hit by the biggest price crash in a generation may have found a lifeline outside of the group.

India, the world’s fastest growing crude consumer whose appetite for fossil fuels is forecast to surge in the next two decades, will likely decide next month on whether to advance $15 billion to Nigeria for future supplies. Essar Oil Ltd., operator of India’s second-biggest refinery, has struck a $13 billion deal which may lead to the plant processing more oil from Venezuela.

With prices languishing at under $50 a barrel, about 55 percent below its 2014 peak, smaller sellers have been the most vulnerable to falling revenues. Nigeria has been pushed to the brink of its first full-year economic contraction in 25 years, while Venezuela struggles to ward off a debt default at its national oil company. Now the two crude producers are finding their own means of survival as OPEC seeks to resolve an impasse over output cuts aimed at stabilizing the market.

“Countries like Venezuela and Nigeria, reeling under financial crisis, will challenge any OPEC decision that works against their economic interests,” said Kunal Agrawal, an analyst with Bloomberg Intelligence. “These countries want to secure long-term supply contracts with the likes of India and China.”

India, which imports more than two-thirds of its oil from the Middle East and whose demand is forecast to double through 2040 to 10.3 million barrels a day, is seeking to diversify its purchases to guard against the geopolitical risks tied to the world’s biggest suppliers like Saudi Arabia and Iraq. Over 80 percent of India’s crude is imported, and with a burgeoning population and an economy projected to grow 7.4 percent next year, companies such as the U.K.’s BP Plc and Russia’s Rosneft PJSC are eyeing a piece of an oil retail market already worth $117 billion.

Rosneft has indicated it intends to process crude from its share of oil fields in Venezuela at Essar’s refinery after the Russian company’s acquisition of the facility at Vadinar in western India. Nigerian oil minister Emmanuel Ibe Kachikwu said last month that the West African nation is looking to sign a pact with the Indian government for $15 billion in advance payments for its oil in December.

Welcome Respite

“You can’t depend on one country, but you have a basket of countries from where you take,” said Mukesh Kumar Surana, chairman of India’s state-run refiner, Hindustan Petroleum Corp. “So there will be opportunities for smaller producers.”

Those deals are a welcome respite for Nigeria and Venezuela. Nigeria, which counts oil as its biggest foreign-exchange earner, could see its gross domestic product shrink 1.7 percent this year, according to the International Monetary Fund, its first full-year contraction since 1991. Venezuela has faced widespread shortages of food and essential products as the price of oil, which accounts for 95 percent of its foreign currency earnings, collapsed.

The Latin American nation’s state-owned oil company, Petroleos de Venezuela SA, has struggled with its finances this year after the price it receives for its exports has plummeted 63 percent from over $100 a barrel in 2014. PDVSA, as the company is known, said last month that creditors holding $2.8 billion of bonds that come due over the next year agreed to extend maturities in a highly anticipated swap that will buy the company some time.

http://www.bloomberg.com/news/articles/2016-11-23/bruised-oil-nations-seek-solace-in-fastest-growing-crude-guzzler

Investment in new oil production is likely to fall for a third year in 2017 as a global supply glut persists, stoking volatility in crude markets, the head of the International Energy Agency (IEA) said on Thursday.

"Our analysis shows we are entering a period of greater oil price volatility (partly) as a result of three years in a row of global oil investments in decline: in 2015, 2016 and most likely 2017," IEA director general Fatih Birol said at an energy conference in Tokyo.

"This is the first time in the history of oil that investments are declining three years in a row," he said, adding that this would cause "difficulties" in global oil markets in a few years.

Oil prices have risen to their highest in nearly a month, as expectations grow among traders and investors that OPEC will agree to cut production, but market watchers reckon a deal may pack less punch than Saudi Arabia and its partners want.

The Organization of the Petroleum Exporting Countries meets next week to try to finalise to output curbs.

U.S. shale oil producers will increase their output if oil prices hit $60 a barrel, meaning OPEC will have to walk a fine line if it curtails production to prop up prices, Birol said last week. Brent crude stood around $49 a barrel on Thursday.

He said that level would be enough for many U.S. shale companies to restart stalled production, although it would take around nine months for the new supply to reach the market.

http://www.reuters.com/article/iea-oil-investment-idUSL4N1DP16F

Norway's oil companies have lowered their 2017 investment plans, a Statistics Norway survey showed on Wednesday, raising the chances of a central bank interest rate cut in the coming months.

Norway's biggest industry has curbed spending in the wake of a more than 50 percent fall in oil prices over the last two years, bringing the economy to a near standstill.

The country's oil companies plan to invest 146.6 billion crowns ($17.21 billion) next year, the survey showed, down from 150.5 billion crowns when surveyed in August by Statistics Norway.

"The decline is mainly due to lower estimates for exploration and shutdown and removal (of platforms). Exploration wells and removal projects originally planned for 2017 are now postponed," Statistics Norway said in a statement.

Plans now point to a 10 percent cut versus 2016, economists at Handelsbanken said, much deeper than the approximately 4 percent cut expected by the Norwegian central bank.

"This suggests that the offshore oil sector will continue to drag down Norway's industrial sector and economic activity next year, by maybe more than we thought," Handelsbanken Chief Economist Kari Due-Andresen said.

The oil sector accounts for 20 percent of the Nordic country's economy.

Due-Andresen expects the central bank to leave its key policy rate unchanged at 0.50 percent on Dec. 15 but she said the bank could cut its rate path, or outlook.

Norges Bank has said since September that it expects the key policy rate to stay at 0.50 percent "in the period ahead".

Kyrre Aamdal an economist at DNB Markets, agreed that the central bank would likely leave the rate untouched as it worries about overheating in the housing market.

However, "the downside risk is high and has increased after the oil investment numbers," Aamdal said.

http://www.reuters.com/article/norway-oil-investment-idUSL8N1DO12W

A new Japanese regulatory probe into sales restrictions for liquefied natural gas (LNG) contracts will be at the forefront of discussion as the industry's biggest buyers and sellers gather in Tokyo this week.

Representatives from major LNG producers Qatar, Australia and Malaysia will meet with buyers from companies including Japan's Jera Co, the world's biggest buyer of the fuel, and Taiwan's CPC Corp to find ways to address a market where demand is only about 76 percent of supply, Thomson Reuters Eikon data shows. The overhang is leading the industry to question everything from how the fuel is priced to how it is sold.

Adding to the disruption, the Japan Fair Trade Commission is examining whether destination clauses, long-time features of LNG sales contracts that restrict buyers from selling cargoes to third parties, are anti-competitive. The investigation could force the renegotiation of billions of dollars of existing LNG contracts.

Buyers in Japan, the world's biggest LNG importer, have long complained about destination clauses and will voice their displeasure again at the LNG producers and consumers conference on Thursday.

"It is desirable to have no destination restrictions," Takehiro Honjo, president of Osaka Gas, Japan's second biggest city gas company, said on Friday. He added that about 20 percent of its current LNG contracts do not have the clauses.

Japan's buyers are now overcommitted to their contractual LNG cargoes as demand is dropping. They want more leeway to resell the spare cargoes but are prevented by the clauses.

"Japan appears to be following Europe's example, (which) led to these clauses being reviewed in a number of gas and LNG supply arrangements and supported improved flexibility," said Kerry Anne Shanks, vice president, Asia gas and LNG research, at Wood Mackenzie.

She pointed to the example of Spain, where re-exports of cargoes totalled nearly 4 million tonnes in 2014. A cargo is typically about 110,000 tonnes.

Producers have rebuffed the objections. But, they are having to reconsider that position because of increasing U.S. LNG exports, which do not carry the destination restrictions.

Japan, Europe, South Korea, China and India, which together account for about 80 percent of the world's total LNG imports, have jointly called for relaxing or abolishing the destination clause, Japan's trade ministry said.

Major sellers could be convinced to relax or remove the restrictions if buyers would make other concessions, said a source familiar with their thinking.

"Cancelling the clause will have to result in some give elsewhere," said the source.

But with prices down by nearly two-thirds from their 2014 high LNG-AS and more supply coming to market, gas consumers, who use the fuel for power generation and for cooking, have more power to force through changes.

"It's a buyers market now. We are asking them (sellers) not to include destination restrictions as much as possible and we have made some progress on reaching an understanding," Tokyo Gas Executive Officer Kentaro Kimoto, who is in charge of the company gas resources department told reporters on Monday.

http://www.reuters.com/article/lng-japan-idUSL4N1DN1WK

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Mozambique’s state-owned energy firm Empresa Nacional de Hidrocarbonetos (ENH) has given its approval for the financing of the development of the Coral south FLNG project.

The approval comes less than a week after Italian oil and gas firm Eni, which is the operator of the Coral offshore gas discovery, gave its financing approval for the project.

The Area 4, located in the deep waters of the Rovuma Basin, contains the giant Coral South gas field for which the investment decision was made by Eni’s board of director last week.

Mozambican media have reported that the expected total investment for the project will be $8 billion, of which ENH will provide $800 million.

ENH owns a 10 percent stake in the project. Eni operates the offshore Area 4 with a 50 percent indirect interest, owned through Eni East Africa (EEA), which holds a 70 percent stake of Area 4. The remaining 20 percent stake in EEA is owned by China’s CNPC. EEA’s partners in Area 4 are Galp, Kogas, and ENH with a 10% stake each.

All the partners need to give their financing approvals before the Final Investment Decision (FID) is made. The FID is expected to be reached by the end of 2016.

The FID will represent the first phase of development of 5 trillion cubic feet of gas in the Coral discovery in deep waters some 80 kilometers offshore of the Palma bay in the northern province of Cabo Delgado.

The giant discovery, made in May 2012 and outlined in 2013, proved the existence of a high quality field of Eocenic age with excellent productivity. It is estimated to contain 15 trillion cubic feet of gas in place, wholly located in Area 4.

Eni in October secured a major push towards the Final Investment Decision. Namely, Eni and its partners in the Area 4 concession have managed to find a major customer for the gas to be produced there – British energy major BP.

Under the agreement, BP will buy all the LNG to be produced by Eni’s Coral South Floating LNG unit, which will be installed offshore Mozambique, over a period of 20 years. Commercial details of the agreement were not disclosed.

http://www.offshoreenergytoday.com/another-partner-gives-financing-nod-for-coral-south-flng/

Canacol Energy Ltd. is pleased to provide the following update concerning the execution of 100 million standard cubic feet of new gas sales contracts to existing and new customers located on the Caribbean coast of Colombia, and the initiation of a private pipeline venture that will deliver 40 MMscfpd of new gas production to new and existing customers located on the Caribbean coast in 2017.

New Gas Sales Contracts

Further to its November 10, 2016 announcement of a new transportation agreement with Promigas S.A. to ship 100 MMscfpd of new gas production, the Corporation has negotiated 4 new take or pay gas sales contracts totalling 100 MMscfpd with existing and new thermoelectric, refining, industrial, and commercial customers located in Cartagena and Baranquilla. The contracts all commence in December 2018, have a term of between 5 and 10 years, and are with large, established offtakers. The pricing of these new contracts, combined with the Corporation's current multi-year take or pay gas contracts, and the private pipeline sales as described below, results in an average contract price of approximately US$ 5.00/mcf for the anticipated 230 MMscfpd of production in December 2018.

Private Pipeline

A Special Purpose Vehicle ('SPV') has been formed to build a new private gas pipeline connecting the Corporation's gas facility located at Jobo to the Promigas operated pipeline at Sincelejo. The private pipeline will consist of approximately 80 kilometers of flowlines and two compression stations, and is designed to transport 40 MMscfpd of Canacol's gas to new and existing customers located in Cartagena under take or pay contracts at existing prices. Surveying and permitting for the new pipeline is underway, with first gas transportation anticipated in December 2017. The SPV is anticipated to raise approximately US$ 50 million in a combination of equity and debt, outside of Canacol, to construct and operate the pipeline.

Corporate Gas Production Forecast 2017 and 2018

Based upon the above mentioned new private gas pipeline, the new gas sales contracts, and the recently announced agreement whereby Promigas will add 100 MMscfpd of new transportation capacity to the existing pipeline to Cartagena and Baranquilla by December 2018, the Corporation is planning to increase current gas sales from 90 MMscpf to 130 MMscfpd in December 2017, and to 230 MMscfpd in December 2018.

The Corporation expects to have approximately 190 MMscfpd of productive capacity from the 11 existing wells drilled in its Nelson, Palmer, Nispero, Trombon, Clarinete and Oboe gas fields combined with two remaining 2016 development wells (Clarinete 3 and Nelson 8) being drilled prior to year end 2016. In addition, the Corporation's facility located at Jobo has 190 MMscfpd of gas processing capacity.

http://www.oilvoice.com/n/Canacol-Energy-announces-new-gas-sales-contracts-private-pipeline-and-2017-and-2018-gas-production-forecast/9a53f1f9c8c0.aspx

The way US E&P operators are adding rigs, planning activity ramp-ups, preparing to raise capex and looking forward to renewed production growth in 2017, you'd be tempted to write finis to a harrowing two-year industry downturn.

During third-quarter 2016 earnings calls in the last few weeks, oil operator after operator unveiled what became surprisingly repetitive near-term plans: stirring the production pot by slipping a rig or two into the field during the final months of this year, kicking up the capital budget modestly and then returning to production growth in 2017.

'Third quarter results tell the story of good, old fashioned American ingenuity,' Robert W. Baird analyst Ethan Bellamy told S&P Global Platts. 'Costs are down, productivity is up, and capital is flowing into the most productive regions.'

CEOs certainly displayed sunnier dispositions on conference calls than a couple of quarters ago when the specter of what then was a recent period of $30/b oil was fresh in their minds.

But now, with a new year looming, oil executives seemed energized by their victory over a low-priced oil world after two years of squeezing costs and efficiencies from oil fields and developing precise completion designs to extract still more oil and gas per well. So they appeared willing to open the purse strings a bit next year-and if oil prices cooperated, rev up the drilling machine and production spigot in the months to come.

But beneath their show of confidence, oil executives appeared mindful of the sobering and ongoing volatility of oil prices. Most clearly conveyed that any stepped-up activity would be done prudently until price signals indicated otherwise. Larger operators in particular said higher prices of mid-$50s/b to $60/b were needed for next-stage growth.

Paul Horsnell, head of commodities research for Standard Chartered Bank, noted industry still is not investing according to the oil price curve. Front-month WTI closed Friday at $45.69/b, while forward prices in June and December 2017 settled at $49.49/b, and $50.60/b, respectively.

'On average, they are maybe planning on the basis of the curve minus at least $5' per barrel, Horsnell said. 'So, not overly aggressive.'

But even as the outlook for 2017 turns up, independent E&Ps as a group showed financial losses from July to September for the eighth straight quarter, he said.

Despite losses, rig count growing

While the losses were half that of three months before and only 15% of the loss in the same 2015 period, 'it was another loss on top of a lot of other losses,' he said.

Q3 results 'show an industry that is behaving like survivors from a storm: very happy to be alive, but still facing the task of clearing up a lot of wreckage,' Horsnell added.

While 153 oil rigs have been added in US fields during the last six months, and 19 in the last week alone, not all operators are necessarily planning production growth. Some are preparing for flat output next year. ConocoPhillips is eyeing flat to 2% growth in 2017 output while others, like Whiting Petroleum and Murphy, could hold next year's output flat with Q4 2016.

On the other hand, several operators have forecasted double-digit output growth, notably from the Permian Basin in West Texas and New Mexico: Pioneer Natural Resources expects 13% to 17% production increase next year that includes 23% to 27% oil output growth. Concho Resources sees 20% per year total production growth for 2017-2019 and Diamondback Energy eyes more than 30% output growth.

To meet those estimates in the Permian Basin, operators added 50 rigs in Q3 and so far in Q4 have added another 26 to a total of 229 rigs, nearly 100 more than all other major US shale plays combined.

Although the EIA has forecasted US oil production down 110,000 b/d or 1.2% for 2017 year over year, the agency 'may be underestimating the capital efficiency being realized by US E&Ps, UBS analyst Bill Featherston said in a recent investor note. And that could potentially 'prolong the oil price recovery or lower the medium-term normalized oil price.'

UBS' own oil production model, based on EIA data, currently calls for 2017 volumes to be down roughly 340,000 b/d year over year or 4%, and 2018 output up around 85,000 b/d or 1% year on year.

While oilfield service and equipment providers recently cautioned they would likely soon take back some of the 15% to 30% or more in price concessions granted to oil companies early in 2015, this may not happen until late next year or possibly even 2018, Robert W. Baird analyst Dan Katzenberg said.

http://www.oilvoice.com/n/End-of-downturn-at-hand-Operators-behavior-suggests-so-Fuel-for-Thought/90663a04aff3.aspx

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Attached Files

                                                      Last Week    Week Before   Last Year
Domestic Production '000............ 8,690              8,681            9,165
Alaska ............................................ 511                      514               528
Lower 48 ........................................ 8,179              8,167             8,637

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

U.S. crude oil refinery inputs averaged 16.4 million barrels per day during the week ending November 18, 2016, 271,000 barrels per day more than the previous week’s average. Refineries operated at 90.8% of their operable capacity last week. Gasoline production decreased last week, averaging 9.7 million barrels per day. Distillate fuel production increased last week, averaging 5.1 million barrels per day.

U.S. crude oil imports averaged about 7.6 million barrels per day last week, down by 845,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 8.1 million barrels per day, 13.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 855,000 barrels per day. Distillate fuel imports averaged 136,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 1.3 million barrels from the previous week. At 489.0 million barrels, U.S. crude oil inventories are at the upper limit of the average range for this time of year. Total motor gasoline inventories increased by 2.3 million barrels last week, and are well above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories increased by 0.3 million barrels last week and are well above the upper limit of the average range for this time of year. Propane/propylene inventories rose 1.8 million barrels last week and are near the upper limit of the average range. Total commercial petroleum inventories decreased by 0.1 million barrels last week.

Total products supplied over the last four-week period averaged about 19.9 million barrels per day, up by 1.6% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 9.2 million barrels per day, up by 0.6% from the same period last year. Distillate fuel product supplied averaged 4.0 million barrels per day over the last four weeks, up by 1.9% from the same period last year. Jet fuel product supplied is up 10.2% compared to the same four-week period last year.

Cushing down 100,000 bbl

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

U.S. Gulf Coast refinery utilization has nearly recovered from fall maintenance season with only two units left in restart mode following planned work as of November 21.

The 124,500 bpd fluid catalytic cracker and associated 26,600 bpd alkylation unit remained below normal operating levels since being shut late September at Marathon's 464,000 bpd Garyville, LA, refinery. October was the heaviest month of maintenance in the Gulf Coast this year, according to Genscape.

The largest maintenance projects this fall were at Valero's 292,000 bpd Port Arthur, TX, refinery, which completed after the restart of a hydrocracker on November 6, and Marathon's Garyville refinery, where units are restarting. Valero's plant-wide overhaul was expected for completion in late October, according to Reuters.

A multi-unit overhaul underway at Valero’s 292,000 bpd Port Arthur, TX plant on Oct. 3. Maintenance activity was completed on Nov. 6 with the restart of a hydrocracker. Click to enlarge

During the maintenance season, at least 11 percent of Gulf Coast FCC capacity was shut in October. Monitored FCCs that shut for planned work in October include Shell's 70,000 bpd unit in Deer Park, TX, Petrobras' 56,000 bpd Houston unit, Valero's 96,000 bpd unit in Corpus Christi, TX, and Marathon's 124,500 bpd unit in Garyville, LA.

Marathon's Garyville FCC will be down for the longest period, shut for 56 days as of November 21. The Garyville FCC was also the only FCC monitored by Genscape that was shut in October 2015 for planned work. The 2015 work was completed in 19 days, according to Genscape.

Fall maintenance in the U.S. Gulf Coast increased in 2016, reaching a maximum capacity offline of 11 percent on October 10. Maintenance in 2015 was uncharacteristically low with companies running units to capture relatively healthy refining margins and relatively weak crude prices. The maximum capacity offline monitored by Genscape in fall 2015 was 2.46 percent, or 226,000 bbls, on November 3, 2015. The U.S. benchmark West Texas Intermediate (WTI) price closed that day at $47/bbl. In 2014, the maximum outage was 8.22 percent, or 550,000 bbls, on November 1.

Genscape's North American Refinery Intelligence Service combines observations obtained from infrared cameras with in-house analytical and technological expertise to provide an unrivaled view into real-time operations at U.S. and Canadian refineries. Genscape currently monitors 80 percent of overall refinery capacity in the United States, including 92 percent of East Coast refineries, 84 percent of Midcontinent refineries, and 91 percent of Gulf Coast refineries. To learn more, or request a free trial of the North American Refinery Intelligence Service, click here.

- See more at: http://www.genscape.com/blog/us-gulf-coast-refinery-maintenance-nears-completion#sthash.HSVZtTxY.dpuf