State-owned oil transportation monopoly Transneft says Russian oil companies have applied for 215 million tons of crude exports in 2016. This is 6.4 percent less than last year, business daily Vedomosti reports.

In 2015, the situation was the opposite for Transneft, which accounts for almost 90 percent of Russian oil shipments. The company transported seven percent more oil than in 2014.

Chevron is about to begin exports from its massive Gorgon LNG project on Barrow Island off WA. 

Chevron has marked a milestone in preparations to start exports from its delayed $US54 billion Gorgon liquefied natural gas project in Western Australia, signalling that the first shipment from the country's biggest single resources project is just around the corner.

The US gas major advised on Friday that an LNG cargo had arrived at the plant on Barrow Island off the WA coast to be used to cool down the infrastructure ahead of the first shipment.

Chevron Australia managing director Roy Krzywosinski described the moment as "a significant milestone" for the venture, which was originally scheduled to begin production in late 2014.

"The commissioning cargo is essential for the final testing of critical systems and to efficiently cool down the plant prior to the start of LNG production," Mr Krzywosinski said in a statement.

Gorgon, which was sanctioned for construction in September 2009, will eventually produce some 15.6 million tonnes a year of LNG, tapping massive Gorgon and Jansz-Io fields in the Carnarvon Basin for supply to customers in Japan, South Korea, India, China and elsewhere.

It was originally budgeted at $US34 billion but has suffered a series of cost blowouts, partly on foreign exchange, partly on weather delays and some labour productivity issues.

The venture is coming into production just as spot LNG prices in Asia are seeing some of their lowest levels for years amid disappointing demand in China and falling consumption in the two biggest markets, Japan and South Korea. Contract prices are also in the dumps because of the collapse of crude oil prices.

However the venture, which is 25 per cent owned by each of Shell and ExxonMobil, is due to produce for several decades, potentially for 40 years or more.

"Gorgon will be a long-term supplier of natural gas to our customers in the Asia-Pacific region and in Australia, delivering energy security as well as significant long-term economic benefits to Australia for decades to come," Mr Krzywosinski said.

The Chevron-operated LNG vessel, Asia Excellence, delivered the commissioning cargo to cool down the storage and loading facilities ahead of the first LNG export cargo from Gorgon, which Chevron said is planned "in early 2016."



Read more: http://www.smh.com.au/business/energy/chevron-nears-start-of-exports-from-us54b-gorgon-lng-20160115-gm6k6e.html#ixzz3xIjFPCH9
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As clock ticks down on sanctions, oil-laden Iran tankers set to target India and Europe

With Iran poised to resume usual business ties with the world under a historic nuclear deal, Tehran is set to target India, Asia's fastest-growing major oil market, and old partners in Europe with hundreds of thousands of barrels of its crude.

Iran expects the U.N. nuclear watchdog to confirm on Friday it has curtailed its nuclear program, paving the way for the unfreezing of billions of dollars of assets and an end to bans that have crippled its oil exports.

Tehran plans to lift exports by 500,000 barrels per day (bpd) post-sanctions and gradually raise shipments by the same amount again, adding to a glut of global oil and likely putting more pressure on oil prices which have already dropped 70 percent since 2014 to around $30 per barrel.

Iran has 22 Very Large Crude Carriers (VLCC) floating off its coast, with 13 fully or almost fully loaded, mapping data on Thomson Reuters' Eikon showed, carrying enough crude to meet India's import needs for almost a week.

A senior Iranian source close to supply negotiations said that the country - which has the world's fourth-biggest proven oil reserves - was targeting India as its main destination for crude.

"Indian crude demand is growing faster than other Asian countries. Like our competitors, we see this country as one of the main targets for Asian sales," said the official, who spoke on condition of anonymity.

Iran hopes to raise its exports to India by 200,000 bpd, up from the 260,000 bpd currently shipped under sanctions' restrictions, the official said.

At the right price, Indian refiners said they were keen to import more from Iran, as the country's demand for fuel soars on the back of 10 percent annual growth in car sales, a rate that is now faster than China's.

"We have a long-lasting relationship with Iran and post lifting of sanctions we will evaluate the scenario," said L K Gupta, managing director of India's Essar Oil.

"It makes sense to buy oil from nearby options (like Iran)," said H. Kumar, managing director of another Indian oil firm, Mangalore Refinery and Petrochemicals, but added "intake will depend on prices." The Iranian official said there was not much room for major export increases to China, South Korea or Japan due to slowing demand and also because of a shift there towards more non-Middle East crudes. A South Korean refinery source confirmed he did not expect a big increase in Iranian supplies, largely because of plentiful alternatives.

A Japanese refiner said that his firm could only take Iranian deliveries once it had insurance in place, which could take time.

Iran already trades limited amounts of oil mainly with Asian buyers legitimately under sanctions, but its crude exports have fallen to just over 1 million bpd, down from a peak of over 3 million bpd in 2011, pre-sanctions.

The Iranian official said Tehran planned to revive supply deals with European partners in order to ramp up exports.

Shipping industry association BIMCO confirmed that European clients would be among the first post-sanction clients.

"Former clients of Iran are the ones who are likely to return as buyers... Italy, Spain and Greece were the top EU importers in 2011," said Peter Sand, BIMCO's chief shipping analyst.

Following years of under-investment, Iran needs foreign cash to modernize its creaking oil industry.

Italy's ENI, Spain's Repsol and France's Total were some of the companies with the biggest delegations at a conference in Tehran last November, during which Iran published new terms for foreign oil investors.

http://www.reuters.com/article/iran-oil-exports-idUSL8N14Z01Q

State-run energy firm YPF said on Thursday it had signed a preliminary deal worth more than $500 million over three years with American Energy Partners LP (AEP) to explore for shale gas in Argentina's vast Vaca Muerta formation.

Argentina sits atop some of the world's largest shale resources but is a net energy importer after years of under-investment in the country's energy sector. YPF says $200 billion over a decade are needed to reverse the deficit.

That task has been made more complicated by the rout in global oil prices.

The foray into Argentina by American Energy's Aubrey McClendon comes months after the former CEO of Chesapeake Energy Corp hired investment banks to shore up the finances of his Oklahoma-based oil and gas venture.

In a statement, YPF said the joint venture involved a pilot project in the Bajada de Anelo block, located in Argentina's Neuquen province that would run until mid-2018.

If the project is continued, Pluspetrol and the province-owned Neuquen Oil and Gas would join the venture, exploring the southern zone of another bock Cerro Areno. A company affiliated to American Energy Partners would take up to a 50 percent stake in both blocks.

McClendon co-founded Chesapeake Energy in 1989 and turned it into a top U.S. gas producer. He resigned from the company in 2013 following a corporate governance crisis.

McClendon went on to form AEP, whose financial backers have included Houston-based private equity firm Energy and Minerals Group.

http://www.reuters.com/article/argentina-ypf-aep-idUSL2N14Y2NK20160114

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During the U.S. shale boom, fortune favored the bold drillers that discovered and pumped oil fastest. Today the winners are producers like Pioneer Natural Resources who best shielded themselves from tumbling prices.

Using derivative transactions known as swaps and collars, the Texas-based firm locked in a minimum price for 85 percent of this year's production. As a result, it gets $60 per barrel for a large chunk of its output while many rivals are selling at the market price of around $30, often not even enough to cover the cost of drilling new wells.

Pioneer shares, though down 23 percent since the start of 2015, outperform a broad S&P index of oil and gas producers energy sector whose value dropped 46 percent. The company also managed to sell $1.4 billion worth of new shares to investors this month - a rare feat in a market that has shut for most energy issuers.

Its executives are not gloating over their winning hedging formula, but they are certainly sleeping better, chief operating officer Tim Dove says.

Dove told Reuters Pioneer forged its strategy, which entails hedging production two or three years in advance, after the 2008-2009 oil market crash caught it virtually unprotected. Battling for survival, the company idled 97 percent of its drilling rigs and its executives did not want to go through such "draconian cuts" ever again, he said.

"If we're going to protect ourselves, we're going to protect heavily," Dove said, describing the company's philosophy.

Now, with crude prices down by 70 percent since mid-2014, that strategy is paying off.

A Reuters analysis of late 2015 filings by the 30 largest U.S. oil firms showed Pioneer had 60 million barrels of oil hedged through 2017, nearly twice as much as any other major U.S. shale producer. (Graphic:tmsnrt.rs/1mYaS0M)

That could bring Pioneer a windfall of more than $730 million this year if oil prices stayed near current 12-year lows, according to a Reuters analysis of company data.

Tim Rezvan, energy analyst with Sterne Agee CRT, estimates that while Pioneer could get 23 percent of its revenue from oil and gas hedging this year, the majority of drillers have little or no output with price guarantees in 2016.

TIME OF RECKONING

Shale producers face a moment of reckoning after a decade-long fracking boom nearly doubled U.S. oil output and turned the United States into the world's leading natural gas producer.

With costs for new drilling in some U.S. shale areas as high as $50 a barrel, the price rout has already triggered several bankruptcies, and tightened credit for those that remain active.

For Pioneer or its smaller rival Newfield Exploration that inspired its hedging program, locking in prices for the bulk of their future production has become a part of their annual business planning.

Newfield Chief Financial Officer Larry Massaro told Reuters hedging has been a strategic pillar for more than a decade for the Texas-based producer. It has a team that meets as often as daily to review its positions.

In global markets, Mexican state oil giant Pemex stands out as an adept hedger, having locked in a $49 price per barrel for 212 million barrels of planned oil exports this year.

But for many other oil producers to hedge or not to hedge is a daunting tactical choice.

During the long spells of $100 plus oil between 2009-2014 many drillers were reluctant to fix their prices as it meant foregoing considerable potential gains if prices moved higher.

When prices started to fall in 2014, producers faced another dilemma - buy protection against a further decline and risk losing out if there is a bounce or double down on a quick price recovery, leaving themselves fully exposed to a further slump.

That is what happened to Continental Resources. Its CEO Harold Hamm announced in November 2014 that it had cashed all of its hedges, pocketing $433 million, to "fully participate in what we anticipate will be an oil price recovery."

Analysts estimate the fateful decision has cost Continental more than $1 billion by now.

Some hedge funds and oil consumers, such as airlines, have also lost money by ending up on the wrong side of hedging bets.

In contrast, Pioneer's hedging has saved it around $1.6 billion since 2014, Dove estimated.

It has also helped Pioneer plan to lift output by as much as 20 percent annually through 2018 even as the U.S. government expects national production to fall 9 percent over the next two years.

"We're one of the few companies that is out there doing a lot of drilling," Dove said.

Pioneer, which ranks among the top 10 U.S. oil and gas producers by market value, pumps around 106,000 barrels of oil per day and is one of the largest players in the low-cost Permian basin that straddles Texas and New Mexico.

$50 HANDLE

Yet even the most comprehensive hedging program cannot offer a blanket protection against the downturn. Earlier this month, Pioneer said it planned to write down as much as $1 billion in South Texas Eagle Ford shale assets due to falling oil prices.

In racing to drill more wells, Pioneer also risks losses if crude prices stay low for longer or crater to the $20 per barrel level that some major banks have warned about.

The latest slide also makes it impossible for Pioneer and other producers to lock in attractive prices for much of their output in 2017 and beyond as options markets now offer swaps for less than $42 on 2017 U.S. benchmark crude.

Newfield is partially hedged into 2017, but it allowed positions representing 5 million barrels to expire recently and has not yet replaced them.

Pioneer locked in prices for about 20 percent of 2017 production when last June 2017 oil futures briefly rose to around $55 a barrel, Dove said, but has done few transactions since then. "We would probably want it to at least have a five handle," Dove said, referring to prices in the $50-60 a barrel range.

http://www.reuters.com/article/oil-hedging-pioneer-idUSL2N14W204

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Yesterday Antero Resources, one of the biggest drillers in the Marcellus/Utica, filed their fourth quarter 2015 operational update.

As in the past they did not disclose their financials–they wait a few more weeks to disclose those numbers. However, as in the past, the operational update is full of great information.

Of chief importance (for us) is how much they sell their natural gas for. Because they have such a great hedging program–locking in future sales at a given price–Antero sold their gas for an average of $4.40 per thousand cubic feet (Mcf) during 4Q15–which is an average of $2.13 MORE than gas sold for at the benchmark Henry Hub! Astonishing. Companies can make money selling gas at those prices.

Antero reports that although 4Q15 production volumes were 18% higher than 4Q14, the volume was down 1% from the previous quarter, 3Q15. Why? Antero is selectively shutting in production at some locations so they don’t have to sell it at depressed prices at the Dominion South and TETCO M2 trading points. Smart.

During 4Q15 Antero drilled and brought online 14 Marcellus wells and 16 Utica wells.

http://marcellusdrilling.com/2016/01/antero-resources-4q15-update-natgas-sales-averaged-4-40mcf/?utm_source=dlvr.it&utm_medium=twitter

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Cheniere Energy has delayed the first export of liquefied natural gas from its Sabine Pass plant by about one month until late February or early March, the company announced Thursday.

The shipment, which was originally secluded to depart near the end of January, is still slated to be the first cargo of liquefied gas to sail from the continental United States.

In a statement disclosing the delay Thursday, the company cited “instrumentation issues” discovered during the final phases of plant commissioning and said it will work to fix them during the next few weeks.

“With construction of Train 1 finished, we remain well ahead of the guaranteed contractual schedule with Bechtel and anticipate no issues in meeting all contractual targets and guaranteed completion date,” said Neal Shear, interim president and CEO of Cheniere.

http://fuelfix.com/blog/2016/01/14/cheniere-delays-first-sabine-pass-lng-export/?utm_source=twitterfeed&utm_medium=twitter#27079101=0

Investments in Norway's key oil and gas sector will fall further in 2016 and in the coming years following a 16-percent drop in 2015, the Norwegian Petroleum Directorate (NPD) said on Thursday, suggesting more pain ahead for the country's economy.

Norway's economy, long one of Europe's best performers, has begun to struggle as its main industry, oil production, is hit by a three-quarters fall in the price of Brent crude since June 2014.

The NPD now sees investments, excluding exploration, falling to 135 billion crowns ($15.3 billion) in 2016 from close to 150 billion in 2015. It predicted a moderate rebound in investments from 2019 onwards.

Its 2016 investment forecast was revised down from an estimate of 137 billion made a year ago, echoing recent forecast cuts by the central bank and Statistics Norway.

"They (investments) are expected to continue their decline going forward, followed by a moderate increase from 2019," the NPD said in a statement.

The directorate noted, however, that its current investment forecasts presume the oil price will increase from today's level in the near future.

"If this presumption proves wrong, and oil prices remain at the current level for a longer period, this could entail further postponement of activities, resulting in even lower investments and exploration costs," it said.

In terms of production, Norway's oil output will drop to 1.53 million barrels per day in 2016 and 1.41 million in 2020 from 1.57 million in 2015, the NPD estimated.

Norwegian gas production will fall to 106.6 billion cubic metres in 2016 from last year's 117.2 billion, rising again to 111.1 billion by 2020, it said.

The directorate said low prices led to oil companies not developing certain hydrocarbon fields. More than half of Norway's oil and gas resources have yet to be produced.

"We see a tendency for the companies to prioritise short-term earnings rather than long-term value creation," NPD chief Bente Nyland said in a statement.

On the positive side, the directorate said oil firms' efforts to cut costs led to more oil development projects becoming more profitable.

Norway's top oil producers include Statoil, Shell , ConocoPhillips, BP, Det norske and Lundin Petroleum.

http://www.reuters.com/article/norway-oil-idUSL8N14Y1P020160114

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According to Reuters, Lithuania has had to put off plans to import US LNG, because the LNG is more calorific than the Russian equivalent, which the state gas system was built to accommodate.

Reuters reports that Ernesta Dapkiene, a spokeswoman for Lietuvos Energija, said: “We are not buying gas from the US at the moment, because the gas they are offering at the moment does not meet specifications needed for our gas distribution system.

They are still testing their liquefaction equipment, and at the moment they cannot ensure the chemical composition of gas, which is needed for Lithuania.

We believe that once the testing phase is over, they will be able to meet our specifications.”

Reuters claims that this test phase could last between 4 – 6 months. Nonetheless, once complete, a long-term contract between Cheniere and LNG shipping company, BG Group, could be signed. Litgas, which is the LNG import arm of Lietuvos Energija, has been discussing LNG deliveries with Cheniere from its Sabine Pass export plant in Louisiana, US.

http://www.lngindustry.com/regasification/14012016/Lithuania-puts-US-LNG-imports-on-hold-1870/

Asian VLCC rates fell again Wednesday, dropping 11 Worldscale points to take the cumulative decline since the beginning of the year to w53.25 amid stiff competition from owners to snap up cargoes to avoid long waiting periods for vessels heading to the Middle East.

The key Persian Gulf to Japan route for a 265,000 mt cargo has slumped by over 44% in the eight trading days so far this year, from 119.25 Worldscale points to w66 Wednesday.

The weakness in the market was writ large with charterers heard to be receiving more than 10 offers on a single cargo on the Persian Gulf to East routes.

Adding to the owners' woes, charterers were seen replacing vessels taken for the Persian Gulf to East voyages by at least 22.5 Worldscale points below initially done levels, mainly due to the ample supply of vessels including newbuild VLCCs, older tonnage and ships that are just out of the dry dock.

"The market is dropping so quickly, much faster than I expected! There are three to four newbuild VLCCs and many owners are keen on one cargo so the market is very competitive," said a VLCC shipowner.

"Around 40-50 vessels will roll over to the February program, and since there are lots of [competitive] vessels remaining in the market it might take some time for the market to rebound," he added.

The drastic cut in rates was described as a "bloodbath," and market participants said that with vessels failing, owners were under pressure as charterers expected to obtain further discounts on rates.

Among fixtures heard, Mercuria replaced the Desh Vibhor with the Ridgebury Pioneer for a PG-East voyage, loading January 15-17 at w47.5 basis 270,000 mt on 2016 Worldscale rates.

This is the fourth vessel taken by Mercuria for this cargo, at a rate significantly lower, having dropped from w75 on the DS Commander.

Shell took two SK Energy re-let vessels, the C. Vision and the Perseus Trader, on subjects for PG-Singapore voyages, loading January 25 and January 27 respectively, both at w57.5 basis 270,000 mt on 2015 Worldscale rates. Sources said Shell previously had the Front Ariake and the Nave Synergy on subjects at w80 for these cargoes.

Market participants said the lowest fixture was S-Oil having placed a newbuild ship, the Gener8 Apollo, on subjects for a PG-Onsan voyage, loading January 27-29, at w44.5 basis 274,000 mt on 2015 Worldscale rates.

http://www.platts.com/latest-news/shipping/singapore/asian-vlcc-rates-fall-again-down-by-44-since-27142925

Statoil ASA, Norway’s biggest energy company, bought a 12% stake in Lundin Petroleum AB, increasing its exposure to the giant Johan Sverdrup field.

The Norwegian oil producer bought about 37 million shares in the Stockholm-based company, Statoil said in a statement on Thursday. Statoil is supportive of Lundin’s management, board and strategy and there is no plan to increase its shareholding in the company.

“We consider this a long-term shareholding,” Statoil CEO Eldar Saetre said in the statement. “The Norwegian Continental Shelf is the backbone of Statoil’s business, and this transaction indirectly strengthens our total share of the value creation from core, high value assets on the NCS.”

The move comes as oil companies cut costs to adapt to a plunging oil price, with Brent crude falling below $30 a barrel on Wednesday. Lundin holds the second-largest stake in the Johan Sverdrup field, Norway’s biggest offshore project in decades. The field is estimated to hold 1.7 billion to 3 billion barrels of oil.

Statoil owns a 40 percent stake in the field, which is scheduled to start production at the end of 2019. Lundin Petroleum AB holds a 23 percent stake, Petoro AS 17 percent, Det Norske Oljeselskap ASA 12 percent and A.P. Moeller-Maersk A/S 8 percent.

http://www.bloomberg.com/news/articles/2016-01-14/norway-s-statoil-buys-minority-stake-in-lundin-petroleum

Oil and gas projects worth $380 billion have been postponed or cancelled since 2014 as firms slash costs to survive the oil price crash, including $170 billion of projects planned between 2016 and 2020, energy consultancy Wood Mackenzie said.

Crude oil prices have fallen by 70 percent since mid-2014 to just over $30 per barrel as soaring global production leaves hundreds of thousands of barrels a day without a buyer, while demand - especially in once-booming Asia - is slowing markedly.

Oil and gas firms were being forced into survival mode as oil prices fell to levels last seen in 2004, Wood Mackenzie (WoodMac) said in a report on Thursday.

"The impact of lower oil prices on company plans has been brutal. What began in late-2014 as a haircut to discretionary spend on exploration and pre-development projects has become a full surgical operation to cut out all non-essential operational and capital expenditure," said Angus Rodger, WoodMac's principal upstream analyst.

The report comes the same week as Barclays bank said global oil and gas companies planned to cut spending on exploration and production by as much as 20 percent in 2016.

WoodMac said a total of 68 major projects with combined reserves of around 27 billion barrels of oil equivalent had been deferred since 2014, with $170 billion of cuts falling between 2016 and 2020.

In terms of production, a total 2.9 million barrels per day (bpd) of liquids production would be deferred into next decade, more than OPEC-member Venezuela produces, it said.

"Against a backdrop of overwhelming corporate pressure to free-up capital and reduce future spend - to the detriment of production growth - there is considerable scope for this wall of output to get pushed back further if prices do not recover and/or costs do not fall enough," the report said.

The average break-even cost for delayed new projects was $62 per barrels of oil equivalent, WoodMac said, adding that deepwater projects had been hit hardest.

These accounted for over half of the total "as companies are forced to rework projects with high breakevens, large capital requirements and high costs."

http://www.reuters.com/article/oil-production-cuts-idUSKCN0US07N20160114

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                                     Last Week    Week Before    Last Year

Domestic Production 000'....... 9,227              9,219            9,192

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

U.S. crude oil refinery inputs averaged over 16.4 million barrels per day during the week ending January 8, 2016, 194,000 barrels per day less than the previous week’s average. Refineries operated at 91.2% of their operable capacity last week. Gasoline production increased last week, averaging over 8.8 million barrels per day. Distillate fuel production decreased last week, averaging about 4.8 million barrels per day.

U.S. crude oil imports averaged 8.2 million barrels per day last week, up by 678,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 7.7 million barrels per day, 4.1% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 446,000 barrels per day. Distillate fuel imports averaged 154,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 0.2 million barrels from the previous week. At 482.6 million barrels, U.S. crude oil inventories remain near levels not seen for this time of year in at least the last 80 years. Total motor gasoline inventories increased by 8.4 million barrels last week, and are above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories increased by 6.1 million barrels last week and are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 4.5 million barrels last week but are well above the upper limit of the average range. Total commercial petroleum inventories increased by 10.0 million barrels last week.

Total products supplied over the last four-week period averaged about 19.3 million barrels per day, down by 3.1% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 8.8 million barrels per day, down by 4.3% from the same period last year. Distillate fuel product supplied averaged about 3.4 million barrels per day over the last four weeks, down by 12.1% from the same period last year. Jet fuel product supplied is down 3.4% compared to the same four-week period last year.

CUSHING CRUDE INVENTORIES REACH RECORD HIGH OF 64M BBL

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

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Premier Oil has confirmed it will acquire E.ON’s North Sea assets in a $120million deal.

The company said the deal had been funded from existing cash resources.

Earlier today the company confirmed it had suspended share on the London Stock Exchange.

Premier will acquire interests in licence in the Central North Sea, West of Shetland and the Southern Gas Basin.

This includes shares in Elgin-Franklin, Huntington, Babbage and Tolmount.

Speculation had begun building earlier today that E.ON was the subject of the reverse takeover.

The company said the deal would add significant production and associated cash flow this year and in 2017 even with the current low oil price.

It also said the deal would allow Premier to share the abandonment cost of exposure on Ravenspurn North and Johnston with E.ON.

Premier Oil chief executive Tony Durant said:”In this challenging macro environment, maximising production whilst cutting costs is critical; both were achieved in 2015 and will continue in 2016.

“Selling our cash negative Norwegian business and re-investing in cash positive UK assets through the proposed E.ON acquisition, is value accretive and materially improves both our current and future financial position.”

Premier Oil said it had “significant liquidity” with cash and undrawn bank facilities of $1.2billion and a year-end covenant headroom in excess of $900million.

It added that the E.ON acquisition would be “materially covenant accretive”.

The company also said the acquisition requires approval from the company’s shareholders, US private placement holders and banks.

It is expected a shareholder circular and notice of meeting will be published in due course.

Yesterday, Broker Jefferies cut Premier’s rating to hold and target price to 33p from 120p.

The firm’s shares fell 33% from 19p to 9.5p – a fraction of May 2014’s high of 358.6p.

Premier Oil’s debt is thought to be more than £1.83billion.

Its current market capitalization is £155million.

The company said progress was also continuing on its Solan project, with first oil now expected in February due to challenging weather conditions which Premier descirbed as “unprecedented”.

The deal comes days after the firm confirmed an oil find in the North Falkland basin.

https://www.energyvoice.com/oilandgas/98521/premier-oil-confirmed-purchase-of-e-on-assets-in-120m-deal/

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China will not cut its domestic retail fuel prices when international oil prices fall below 40 U.S. dollars a barrel, the country's economic planner said on Wednesday.

Previously, China set a ceiling for domestic retail fuel prices, which will not be raised if international oil prices rise above 130 U.S. dollars per barrel.

The floor and ceiling aim to buffer the negative effects of violent fluctuations in international oil prices, according to the National Development and Reform Commission (NDRC).

The latest reforms aim to improve China's oil pricing mechanism, which was introduced in 2013.

Following the new rule, the NDRC on Wednesday announced cuts in the retail price of gasoline and diesel from Thursday. Gasoline prices will drop by 140 yuan (21.34 U.S. dollars) per tonne, while diesel prices will go down by 135 yuan per tonne.

The NDRC has suspended price adjustments of domestic refined oil products twice since Dec. 15, awaiting the changes.

Under the updated mechanism, China will adjust domestic prices of refined oil products when international crude prices translate into a change of more than 50 yuan per tonne for gasoline and diesel for a period of 10 working days, but will not do so if the international prices go below 40 U.S. dollars or above 130 U.S. dollars a barrel.

http://news.xinhuanet.com/english/2016-01/13/c_135006365.htm

Brazil's state-controlled oil producer Petrobras is seeking to sell its 5.8 billion Brazilian real ($1.4 billion) stake in petrochemical producer Braskem SA, newspaper Folha de S. Paulo reported on Wednesday.

Petróleo Brasileiro SA (Petrobras) has hired Brazilian bank Banco Bradesco SA as a financial adviser and has started to pitch the sale to foreign investors, Folha said, without naming sources.

Petrobras owns a 36 percent stake in Braskem, Latin America's largest petrochemical producer. The sale would help Petrobras meet its target of selling $15.1 billion worth of assets in 2015-16, a key part of its plan to cut debt as oil prices plunge to 12-year lows.

Petrobras Chief Executive Aldemir Bendine late last year said the pace of divestments in 2016 would likely be faster than originally expected.

Representatives of Petrobras, Braskem and Bradesco were not immediately available to comment.

http://www.reuters.com/article/petrobras-braskem-idUSL2N14X0H420160113

Oil bounced back after tumbling below $30 a barrel for the first time in 12 years. A persistent oversupply means prices still haven’t staved off the threat of further declines.

Futures rose as much as 2.2 percent in New York, after dropping 3.1 percent on Tuesday. While the industry-funded American Petroleum Institute was said to report U.S. inventories fell 3.9 million barrels last week, government data on Wednesday is forecast to show supplies expanded. The world is now “confronting $20 oil,” according to Citigroup Inc.

“The big picture for the market is still oversupply,” David Lennox, an analyst at Fat Prophets in Sydney, said by phone. “It’s going to be a tough couple of months for prices, $30 oil is very painful.”

Oil May Rise to $60 in 12 Months, UBS's Purcell Says

Supplies at Cushing, Oklahoma, the delivery point for New York futures and the biggest U.S. oil-storage hub, declined by 300,000 barrels last week, the API said Tuesday, according to a person familiar with the figures. Nationwide inventories probably rose by 2 million barrels through Jan. 8, according to a Bloomberg survey before an Energy Information Administration report.

The EIA cut its 2016 forecast for WTI by 24 percent to $38.54 a barrel, according to its monthly Short-Term Energy Outlook Tuesday. U.S. output will drop an average 700,000 barrels a day in 2016, and an additional 270,000 barrels a day next year, the report showed. Production averaged 9.2 million barrels a day through Jan. 1, according to EIA’s weekly data.

“The $20 number is something you have to talk about,” Ed Morse, the global head of commodities research at Citigroup, said Tuesday in Calgary. “When you’ve seen a $10 price slide and WTI is trading just slightly above $30, the likelihood is fairly great. Clearly oil markets cannot maintain a price at below the $30 level for very long. The question is how much longer.”

http://www.bloomberg.com/news/articles/2016-01-12/oil-halts-slide-before-stockpile-data-after-dropping-below-30

China's crude oil imports hit a record 7.82 million barrels a day (bpd) in December, customs data showed, as the world's No.2 oil consumer took advantage of low crude prices to fill strategic reserves, but also increased its exports of refined fuels to an all-time high.

Crude imports for December were 33.19 million tonnes, up 21.4 percent on the month and 9.3 percent on the year, well above earlier estimates by Thomson Reuters Oil Research and Forecasts.

The December import figures may mean China challenges the United States to be the world's top importer of crude, although the U.S. Energy Information Administration has yet to provide its December data. Chinese monthly imports surpassed U.S. imports once, in April 2015.

China shipped in 335.5 million tonnes of crude oil for the year, the data showed on Wednesday. That was up 8.8 percent, or roughly 542,600 bpd, to 6.71 million bpd - also a new record.

Wu Kang, Beijing-based vice chairman of FGE Asia, said the two driving factors behind growth in 2015 were new demand from small, independent "teapot" refineries who gained the right to use imported crude oil in the latter part of the year, and stockbuilding in strategic reserves and commercial storage.

Nearly 20 small refiners have been granted quotas to use imported oil or import oil directly themselves.

China seized the chance to add up to 147 million barrels to its reserves in the first eleven months of 2015, according to Reuters calculations, following a more than 50 percent slump in oil prices LCOc1 since mid-2014.

China said it more than doubled the size of its strategic crude oil reserves between November 2014 and the middle of last year, building inventories at a rate exceeding analyst estimates of the country's stockbuilding.

Industry experts said Chinese firms could expand purchases possibly even more this year, as new tanks become available.

"2016 might be more interesting as the two driving factors are set to become more powerful as the government relaxed control both on crude imports as well as fuel exports, at a pace faster than thought," Wu said.

Demand for crude oil could rise 4.9 percent in 2016, the country's petroleum industry association said on Tuesday.

Even so, with waning economic growth, growth in demand for gasoline was moderate last autumn and appetite for diesel has fallen, putting oil demand - refinery throughput plus net imports of fuels - down 2.5 percent in November.

Fuel exports have risen as a result, hitting a record 4.32 million tonnes in December, or 975,500 bpd, up 5.4 percent on the year. Exports marked a record 693,300 bpd in 2015, up 21.9 percent.

Net fuel exports were 1.48 million tonnes in December.

China has allowed independent refineries to export fuel for the first time, having granted an estimated 440,000 tonnes of quotas under the first batch release.

http://www.reuters.com/article/us-china-economy-trade-crude-idUSKCN0UR0DU20160113

The crude curve has just collapsed, especially since the rebound after China’s Golden Week reprieve ended around October 15. As Alhambra's Jeff Snider notes, the entire futures curve is under $50, an upsetting commentary on everything from US "demand" to long-term implications and especially those that are derived from economists’ somehow continued insistence that this is all just "transitory."

 

 
Transitory just died.

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Attached Files

Yesterday our favorite government agency, the U.S. Energy Information Administration (EIA), issued our favourite report, the Drilling Productivity Report (DPR).

The January 2016 report shows what the EIA predicts oil and natural gas production will be in February from the seven largest commercial shale plays in the U.S. What does the report show?

The biggest drop in production will once again be the biggest natgas producer in the country–the Mighty Marcellus. The EIA predicts the Marcellus will produce 15.222 billion cubic feet per day (Bcf/d) in February, vs. 15.447 Bcf/d in January, a decrease of 225 million cubic feet per day (MMcf/d).

Meanwhile the Utica Shale will continue to show an INCREASE in production month over month–from 3.206 Bcf/d in January to 3.249 Bcf/d in February, a 43 MMcf/d increase month over month. The Utica, for a second month in a row, shows the largest increase in natgas production of all seven plays covered in the DPR.

Overall the DPR shows that oil production month over month will decrease in February, the seventh month in a row, and natural gas will decrease for the eighth month in a row…

http://marcellusdrilling.com/2016/01/eia-jan-dpr-marcellus-production-way-down-again-utica-up/?utm_source=dlvr.it&utm_medium=twitter

Thailand’s PTT Exploration & Production (PTTEP) has made an offer for UK gas major BG Group’s stake in the Bongkot gas field off Thailand, according to a report.

The Bangkok-headquartered wing of state giant PTT is hoping to conclude the purchase of BG’s 22.2% stake in the field within months, Reuters quoted PTTEP chief executive Somporn Vongvuthipornchai as saying.

"We have already proposed an offer and it should be concluded in the first half," he told reporters.

Although not specifying an offer price, Reuters cited him as saying it could be lower than $1.2 billion, given the recent renewed dive in oil prices.

BG, which is in the process of being taken over by Anglo-Dutch supermajor Shell, put the stake up for sale inSeptember, hiring Morgan Stanley to run the sale process. It had hoped to complete a deal before the end of last year.

Thailand accounted for about 6% of BG’s global gas output last year, with the Bongkot field meeting about a fifth of the South-East Asian country’s gas demand.

Thailand’s state-owned PTT Exploration & Production (PTTEP) has a 44.4% stake in the field, while France's Total owns the remaining 33.3%.

Reuters also said PTTEP may chop its $3.4 billion investment budget for this year even further due to the oil price malaise.

http://www.upstreamonline.com/live/1421005/pttep-in-bongkot-offer-to-bg?utm_source=twitterfeed&utm_medium=twitter

Abu Dhabi-listed Dana Gas aims to slash its head office workforce by 40 per cent and cut general and administrative costs by half between 2015 and early 2016, its chief executive said on Tuesday.

The energy company will continue to invest in Egypt and sees its production in the country increasing, Patrick Allman-Ward told reporters on the sidelines of a conference in Abu Dhabi.

Dana produces 34,000 barrels per day of oil equivalent in Egypt, Mr Allman-Ward said, adding its Balsam field in the Nile delta came on stream in late 2015.

The company has operations Egypt, the UAE and Iraq’s Kurdistan region.

http://www.thenational.ae/business/energy/abu-dhabi-listed-dana-gas-to-axe-jobs-slash-costs-by-half

Brazil’s state-controlled oil producer Petrobras has deepened spending cuts and reduced production growth estimates amid the worst oil market in a generation and a massive corruption scandal.

Petroleo Brasileiro SA, as the company is formally known, has slashed its business plan for five years through 2019 to $98.4 billion, the latest adjustment to the original $130 billion in programmed outlays it announced last year, it said Tuesday in a filing. The company reduced its 2020 target for Brazilian oil production by 3.6 percent to 2.7 million barrels a day as a result.

“Petrobras has been working to constantly improve its business plan and rapidly adapt to changes in the business environment,” the company said in the statement.

Rio de Janeiro-based Petrobras has been beset with the collapse in oil prices as it navigates Brazil’s biggest corruption scandal, which blocked some of its suppliers from future contracts and a sent a group of former executives to jail for allegedly taking bribes. The world’s most-indebted oil company still plans to divest $14.4 billion this year to help finance investments.

The company plans to invest $20 billion in 2016, up slightly from its most recent estimate of $19 billion, it said. It expects Brent crude prices to average $45 a barrel this year, down from its previous estimate of $55 a barrel.

Petrobras’ shares fell 4.1 percent to 5.84 reais ($1.45) at 10:57 a.m. local time, the lowest since 2003.

http://www.bloomberg.com/news/articles/2016-01-12/petrobras-reduces-production-estimates-on-deeper-spending-cuts

British oil and gas company BP announced plans on Tuesday to slash 5 percent of its global workforce in the face of a continued slump in oil prices.

It said it aims to reduce its global oil production, or upstream, headcount by 4,000 to 20,000 as it undergoes a $3.5 billion restructuring program. BP said its headcount totaled around 80,000 at the end of 2015.

With crude oil prices at 12-year lows of around $32 a barrel, the world's biggest oil and gas producers are set to continue aggressively slashing spending this year as they face their longest period of investment cuts in decades.

"We want to simplify (our) structure and reduce costs without compromising safety. Globally, we expect the headcount in upstream to be below 20,000 by the end of the year," a company spokesman said.

In the North Sea, he said BP planned to reduce headcount by 600 people over the next two years with most cuts likely in 2016.

BP shares, which have fallen by around 40 percent since the oil price began to slide in mid-2014, were up 1.2 percent at 1157 GMT compared with a 0.8 percent rise for the broader sector index.

Oil companies including Royal Dutch Shell and Chevron have already slashed tens of thousands jobs globally to deal with a near 75 percent drop in oil prices since June 2014 that has seen earnings collapse.

BP, which must also pay $20 billion in fines to resolve the deadly 2010 Gulf of Mexico spill, announced in October plans for a third round of spending cuts and said it would limit capital spending, or capex, to $17-19 billion a year through to 2017.

The company, which has already sold over $50 billion of assets in recent years in order to cover the spill costs, said it expected an additional $3-5 billion of divestments in 2016.

Fourth-quarter upstream earnings for oil majors are expected to fall by 84 percent from a year earlier and 48 percent from the previous quarter, according to analysts at Macquarie.

BP will report fourth quarter and full-year results for 2015 on Feb. 2.

http://www.reuters.com/article/us-bp-cuts-idUSKCN0UQ1HY20160112

Europe refiners rush to make more gasoline after diesel hangover

After years of building up diesel production, European oil refiners are using every trick in the book to maximize gasoline output to meet unabated global demand as the two fuels stage a sharp reversal of fortune.

Many operators on the continent, including Total, BP, Royal Dutch Shell and ExxonMobil, have invested hundreds of millions of dollars over the past decade to increase production of diesel, the road fuel of choice in the region, while seeking to lower gasoline output, seen as a mere "by-product" of that process until recently.

But today the world faces a growing excess of diesel and spectacular demand in Asia and the United States for gasoline and naphtha, a feedstock for plastic manufacturing.

While oil refineries can not maintain high output of gasoline without also ramping up diesel production, they are now taking every possible step to tweak production in order to favour gasoline and naphtha.

One such step is using as feedstock lighter crude oil grades with higher yields of gasoline and naphtha. For example, light Nigerian crude prices have outperformed heavier grades

Some refineries have also opted to lower operating levels, or runs, in diesel producing units known as hydrocrackers.

In recent weeks, as naphtha cracks surged to record levels, some refiners have tweaked the distillation boiling temperature, or "cut point", in order to favour naphtha over kerosene and jet fuel, according to refinery sources and traders.

The results are already showing -- yields of middle distillates, which include gasoil and diesel, dropped to around 50 percent in December, date from industry monitor Euroilstock showed, the lowest in around 6 years.

"We expect European refiners to do all sorts of things... They are already doing this as the market is sending such strong signals. We will see fractions pulled out of the diesel pool and moved into jet and we will see naphtha fractions taken out of jet and moved into light ends," according to Robert Campbell, head of oil products research at consultancy Energy Aspects.

Benchmark European gasoline refining margins, or cracks, rose to around $15 a barrel this week -- nearly three times higher than a year ago and ten times above 2013 levels -- as demand in China and Asia for the road fuel remains unabated.

Diesel cracks, on the other hand, have languished due to rising global production, slower demand and a mild winter that has filled storage tanks to the brim.

The small changes in refining slates are having an incremental effect. A 1 percent swing in yields could lower Europe's diesel production by more than 250,000 tonnes per month, according to Campbell.

"It is not enough by itself to right the market but would help a little bit. A similar development in the U.S. Gulf Coast would shave another 150,000-200,000 tonnes off the balance and that starts to have a pretty significant effect on the overall number of cargoes being shown."

The global shortage in gasoline is expected to continue this year too.

"With new refinery additions less tailored towards light products and increasing demand for petrol in Asia, it appears increasingly likely that the market could find itself short of gasoline again as it did over the summer of 2015," Barclays said in a note.

In the near term, the sharp decline in crude oil prices due to a persistent supply glut is likely to support refining margins but Energy Aspect's Campbell expects "modest" cuts in refining rates in both Europe and the United States.

Once crude supplies tighten towards the end of the year, "that support will go away and margins will really struggle," he said.

http://www.reuters.com/article/europe-refining-idUSL8N14W2GH20160112

OPEC president Emmanuel Ibe Kachikwu said on Tuesday that he expects an extraordinary meeting of the oil cartel in "early March" to address nosediving crude prices.

"We did say that if it (the price) hits the 35 (dollar per barrel), we will begin to look (at)... an extraordinary meeting," said Kachikwu, who is Nigerian minister for petroleum resources.

The prices have hit levels that necessitate a meeting, he told an energy forum in Abu Dhabi, but added that he not yet confirmed with fellow OPEC ministers if they would be willing to attend.

The US crude oil price tumbled below 31 a barrel Tuesday, extending a sell-off that has pushed it to more than 12-year lows amid a global supply glut, a strong dollar and tepid demand.

Saudi-led Gulf exporters within OPEC have so far refused to cut production to curb sliding prices, seeking to protect their market share despite a heavy blow to their revenues.

Kachikwu said that member states differ on the issue of intervention.

"One group feels there is a need to intervene. The other group feels even if we did, we are only 30 to 35 percent of the producers really," as 65 percent of supply comes from non-OPEC countries, he said at the Gulf Intelligence UAE Energy Forum.

"Unless you have this 65 percent (of) producers coming back to the table you really won't make any dramatic difference," he added.

http://www.menafn.com/1094532197/OPEC-president-sees-emergency-meeting-in-March?src=RSS&utm_medium=twitter&utm_source=twitterfeed

Baker Hughes is field trialling a new adaptive production system which the global services firm delivers 300% greater oil production and 200% higher natural gas production compared with its previous artificial lift offering for unconventional plays.

The firm installed its Leap system last month at a depth of 5,200ft in the Mississippi Lime play in Woods County, Oklahoma, for SandRidge Energy.

In continuous operation since its installation, the system was deployed through the deviated section of the wellbore and started on its first attempt with no issues.

Baker Hughes describes Leap as an entirely new approach to artificial lift, designed to adapt to dynamic production profiles typical in most unconventional oil wells.

Artificial lift is used on oil wells to increase pressure within the reservoir and encourage oil to the surface.

Baker Hughes opened its own $60 artificial lift research and technology centre in 2014 in Oklahoma to research and and develop new artificial lift technology after the company recognised that traditional production technologies were not meeting the demands of unconventional oil plays.

It established a team to research innovative artificial lift solutions to address the challenges.

“Until now, operators have had to use 100-year-old technology that was never intended to operate in deep, horizontal wells or to handle the rapidly declining production rates and high gas volumes typical of unconventional reservoirs,” said Wade Welborn, vice president, Artificial Lift Systems at Baker Hughes.

“Leap is the first artificial lift technology designed specifically for these unique production challenges,” added Welborn

Unlike any other positive displacement pumping technology currently available, proprietary software built into the Leap system surface variable speed drive (VSD) integrates with downhole electronics to allow remote adjustments to the pumping system speed and stroke length as production rates change.

The downhole system consists of a positive displacement pump, which can be installed to sit deeper in a well than traditional rod pumps, a submersible linear electromagnetically actuated motor, which drives the pump and eliminates the need for the long rod string (a primary source of failure in rod lift systems) and a sensor, which provides pressure and temperature data to help ensure the highest level of production optimisation and system longevity.

Welborn said: “Leap dramatically reduces the large surface footprint required for traditional rod systems, mitigates potential emission and leak paths and eliminates the safety hazards to wellsite personnel that are inherent with large pump jacks.”

The SandRidge field trial comes only 18 months after approval of the initial system design.

https://www.energyvoice.com/other-news/trainingtechnology/98116/tech-tuesday-baker-hughes-makes-leap-in-artificial-lift-delivery/

Shell’s proposed combination with BG Group came across a first obstacle on the road towards the shareholder vote on January 27 as Standard Life Investment opted to vote against the merger.

Reuters reported David Cumming, head of equities at Standard Life Investments, saying that the proposed terms of Shell’s acquisition of BG are value destructive for Shell shareholders.

Cumming noted that SLI’s conclusion is based on the downside risk to Shell’s oil price assumptions and risks carried by BG’s Brazilian assets. As a consequence of such conclusion, Standard Life Investments intends to vote against the deal.

However, Shell is still expected to have the backing of its investors as the company’s CFO Simon Henry and CEO Ben van Beurden hold talks with leading investors in order to gather information prior to the January 27 vote.

Contrary to Standard Life Investment, Institutional Shareholder Services, advisor of around 5 percent of Shell’s small and medium shareholders supports the deal due to the positive economics to be realized within a short time frame.

http://www.lngworldnews.com/shell-bg-merger-hits-shareholders-bump/

e’re almost there! INEOS, one of Europe’s largest petrochemical companies, had commissioned and purchased two tankers to ferry Marcellus/Utica ethane from the Marcus Hook refinery near Philadelphia to Norway and Scotland.

The final leg of the Mariner East Pipeline is ready to go online, and the twin tankers are ready to be loaded. In February, the first shipment of Marcellus ethane will set sail from Philadelphia bound for Norway…

http://marcellusdrilling.com/2016/01/marcellus-ethane-sets-sail-for-europe-next-month/?utm_source=dlvr.it&utm_medium=twitter

Norway's oil minister refused to be drawn into public debate over whether state-controlled Statoil should cut its dividend because of the fall in oil prices, saying on Monday that such matters are discussed privately with the company's top executives.

The government owns 67 percent of Statoil -- which bowed to investor pressure for increased shareholder payouts by introducing quarterly dividends in 2014 -- but takes an arms's-length approach that gives the board the freedom to make commercial decisions.

Two members of parliament for Norway's ruling Conservatives argued in financial daily Dagens Naeringsliv on Monday that Statoil should reduce the dividend sharply and save the cash for investments.

"I note that Statoil's dividend is being questioned from several sides. As the person responsible for the state's ownership in the firm, I discuss such matters with the leading organs in Statoil, not in public debate," Energy Minister Tord Lien, who represent the populist Progress Party, said in a statement. Progress and the Conservatives have held power in a coalition government since 2013.

Labour unions have protested that Statoil is laying off staff and cutting investment while increasing its debt to pay dividends, but the company has repeatedly said that it has room to raise its leverage.

"Our dividend policy is based on a long-term perspective and our long-term earnings, and is not tied to the current oil price," Chief Executive Eldar Saetre told Reuters on Jan. 7.

However, Statoil's dividends have also been questioned by analysts.

"Overall, we see dividend risk at Statoil higher than most peers," RBC Caital Markets analysts wrote in a research note last week.

Statoil is due to announce fourth-quarter earnings and its quarterly dividend on Feb. 4, when it will also provide a strategy update. The company, which paid a third-quarter dividend of 22.01 cents a share, declined to comment on Monday.

North Sea crude oil currently trades at about $33 a barrel, down by around 70 percent since mid-2014.

Brokerage Swedbank estimates that oil at that level means that Statoil will have negative cashflow of 19 Norwegian crowns per share after 2016 dividend payments if it cuts capital expenditure by 15 percent from 2015 levels.

"In good times, generous dividends should be paid to owners. In bad times, owners should settle for lower dividends," Rune Selmar, head of asset manager and Statoil shareholder Odin Forvaltning, wrote in Dagens Naeringsliv on Monday.

http://www.reuters.com/article/statoil-dividends-idUSL8N14V2ED20160111

When looking for the prime culprit behind widespread weakness in commodity prices, fingers often point squarely at China.

On the supply side, especially in select metals, the world's second-largest economy deserves a hefty portion of the blame for the rout.

But in the case of crude, China has responded to lower prices with a jump in demand, says Barclays' Commodities Analyst Miswin Mahesh. Although, as he notes, there are signs that this increased appetite may soon wane.

Getting a handle on China's true oil demand is notoriously difficult, and estimates will vary widely depending on which analyst you ask. While Mahesh projects that the demand for oil in the world's second-largest economy grew by 5 percent in 2015, he cautions that: "Chinese oil data are finally starting to reflect weak economic activity."

In November, implied oil demand contracted by 2 percent relative to the same period in the previous year, the first such decline since July 2014.

Demand for gasoline remains solid, the analyst notes, but the moderation in the 'old' industrial segments of the economy has dampened the use of diesel.



The moderation in China's economic expansion entails a decrease in the rate of—and sheer size of—demand growth this year, according to Barclays.

"In 2016, we expect Chinese oil demand to grow at a slower pace, of 300,000 barrels per day (3 percent) versus the estimated 510,000 barrels per day in 2015, reflecting the country’s economic slowdown," he concludes.

From 2011 through 2014, implied year-over-year oil demand growth averaged 361,000 barrels per day, according to Mahesh.

http://www.bloomberg.com/news/articles/2016-01-11/china-s-demand-for-crude-is-showing-signs-of-cracking

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Suncor Energy Inc. will probably need to sweeten its bid for Canadian Oil Sands Ltd. after failing to convince enough shareholders to accept a C$4.03 billion ($2.84 billion) offer that management repeatedly rejected for undervaluing the company.

Based on early returns, shareholders believed to represent less than half of the shares outstanding voted to accept the offer of 0.25 Suncor shares for each of Canadian Oil Sands’, a person familiar with the matter said Friday, who asked not to be named because the matter is private. That’s short of the two-thirds of the shares Suncor was looking for.

"They will have to search out any larger shareholders that might have voted against the deal and see what it takes to get it over the hump," Rafi Tahmazian, a Calgary-based fund manager at Canoe Financial LP, said in an e-mail. Tahmazian had owned shares of Canadian Oil Sands and sold his position shortly after the Suncor bid. "I suspect it could be a better ratio" of shares, meaning a higher offer, he said.

Suncor chief executive officer Steve Williams said in a statement Monday he strongly believed in the value of the offer for Canadian Oil Sands, and that he was encouraged by the number of shares tendered. He did not disclose what percentage of shares were tendered by the deadline Friday evening. "We have decided to extend the offer in order to allow shareholders to continue to tender to the offer," he said.

Suncor declined to improve the offer earlier this month even as Canadian Oil Sands’ shareholders including resource investor Seymour Schulich, Burgundy Asset Management and Value Financial, spoke out against the merger. Those who opposed the deal were either looking for a higher offer price or were not interested in selling at all.

Schulich, who currently holds about 5 percent of Canadian Oil Sands’ shares, has floated the idea of a warrant being issued alongside the offer that would protect shareholders if the price of oil rises.

Suncor extended its offer Friday of 0.25 share for each of Canadian Oil Sands to Jan. 27.

http://www.bloomberg.com/news/articles/2016-01-11/suncor-seen-needing-to-raise-canadian-oil-sands-bid-after-rebuff

Nigerian billionaire Aliko Dangote’s industrial complex in the commercial capital Lagos will sell as much as $6 billion a year of foreign exchange to the West African nation’s central bank by 2018, according to Governor Godwin Emefiele.

Dangote’s fertilizer plant, which will be operational next year, and the petrochemical plant and refinery, expected to be completed by 2018, will meet local consumption of petroleum and chemical products that currently make up 35 to 40 percent of Nigeria’s import needs, Emefiele told journalists at the construction site Sunday. The complex will also produce for export, he said.

“We expect that by the time these projects are completed, it will not only meet the needs of our domestic requirement,” Emefiele said. “By the time it is completed, he will be exporting these products to the point where he will be selling foreign exchange to Nigeria, to Nigerians and to the Central Bank of Nigeria to the tune of almost about $6 billion a year.”

Africa’s top oil producer relies on fuel imports to meet domestic needs since its four state-owned refineries produce a fraction of their 445,000 barrels-per-day capacity after decades of poor maintenance, corruption and mismanagement. Nigeria is also struggling to cope with crude prices that have fallen more than 70 percent since their June 2014 peak to below $40 a barrel.

The Abuja-based central bank has resorted to holding the naira at 197 to 199 per dollar since March by introducing trading curbs to conserve reserves and stem a rout after it fell to a record 206.32 in February. While Nigerian President Muhammadu Buhari has supported the governor’s measures, International Monetary Fund Managing Director Christine Lagarde last week called for more flexibility in the monetary policy.

“You can imagine what will happen to the savings in foreign exchange” by the time the refinery, petrochemical and fertilizer plants are completed, Emefiele said. “We can’t wait, we need him to do this very fast so we can begin to save foreign exchange,” he said, referring to Dangote, Africa’s richest man.

http://www.bloomberg.com/news/articles/2016-01-11/dangote-plants-seen-selling-6-billion-yearly-to-nigeria-by-2018

IHS Inc said it agreed to buy U.S.-based Oil Price Information Service (OPIS) for $650 million to add real-time pricing information to its energy analytics business.

OPIS, which provides information used for commercial contracts and to settle trades, has presence in 30 countries, IHS said.

The acquisition is IHS's second in a less than a month. The company agreed in December to buy Canada-based vehicle data provider Carproof Corp for $460 million to boost its automotive research business.

OPIS provides real-time and historical spot, wholesale/rack and retail fuel prices for refined products, renewable fuels, and natural gas and gas liquids industries.

The acquisition "gives IHS visibility across the entire petroleum value chain, from wellhead to consumer," Chief Executive Jerre Stead said on Monday.

Stead had said earlier that IHS could pursue some "larger acquisitions" of at least $500 million in the industrial and energy research sectors.

http://www.reuters.com/article/opis-ma-ihs-idUSL3N14V3JH20160111

Ardian targets energy shake-out with infrastructure fund

French private equity firm Ardian is seeking to profit from a shake-up of the oil industry after raising a record 2.65 billion euros ($2.89 billion) infrastructure fund.

Half of the new fund is targeted at the transport sector and half on energy as it anticipates low oil prices will trigger dramatic changes in the oil industry, Ardian head of infrastructure Mathias Burghardt told Reuters on Monday.

"Oil groups are divesting mid- and downstream assets and we are ready to invest in some of these, having done two such deals already," Burghardt said.

"As an indication of the change, Saudi Aramco has announced (plans) to divest stakes of some oil-related assets and we will look at them," he said, adding the new fund could invest 20 percent of its money outside Europe.

He said Ardian also had a keen interest in northern Europe, although it had not yet decided whether to invest in German gas network operator Thyssengas.

Ardian, which manages or advises on the management of $50 billion in assets, was the private equity investing arm of French insurer AXA until it was spun off in 2013 in an employee buyout. It said that the new fund was the biggest ever raised to invest in European infrastructure and that it brought its assets under management targeting the sector to $7 billion.

The fund, its fourth focused on infrastructure, attracted institutional investors from pension funds, insurers and sovereign wealth funds with locations ranging from Europe to North America and Asia, Ardian said.

Ultra-low government bond yields mean institutional investors are being tempted into Europe's infrastructure market in search of higher and stable long-term returns.

One billion euros of the new Ardian fund have already been committed, with investments in Italian airport firm 2i Aeroporti, Repsol's CLH oil transport and storage subsidiary, Portuguese toll-road operator Ascendi and French oil transport and storage firm Geosol.

http://www.reuters.com/article/ardian-infrastructure-idUSL8N14V1YC20160111

The ConocoPhilips-operated Australia Pacific LNG project has on Saturday shipped its first cargo of liquefied natural gas from the Curtis Island facility near Gladstone.

The first cargo was loaded onboard the Methane Spirit LNG carrier, Origin Energy, one of the project partners, said in a statement.

The second cargo of chilled gas is expected to be shipped soon from the A$25 billion (US$17 billion) APLNG plant.

However, the first cargo was planned to be loaded before the end of 2015. The delay has caused issues for another APLNG partner, China’s Sinopec that has had the BW Pavilion Vanda LNG carrier waiting at anchor off Gladstone since December 18. As Reuters reports, due to the delay, Sinopec racked up more than US$500,000 in demurrage costs.

Sinopec has a 7.6 mtpa long-term contract  with APLNG while Japan’s Kansai Electric has booked 1 mtpa of LNG from the facility on a 20-year deal.

Australia Pacific LNG CEO, Page Maxson said that the full production capacity of 9 million tons per year from the APLNG facility is expected to be reached in 2016.

With the start-up of APLNG’s first train, all three liquefied natural gas facilities on the Curtis Island near Gladstone have entered operation.

http://www.lngworldnews.com/aplng-ships-inaugural-cargo/

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The number rigs drilling for oil in the U.S. plummeted by another 20 rigs during the first week of 2016 as the energy sector continues to struggle.

West Texas’ seemingly resilient Permian Basin led the way with the loss of eight rigs, while southern Texas’ Eagle Ford shale dipped by five rigs, according to weekly data released by oil field services firm Baker Hughes.

The sharp cutbacks starting the new year might represent the first sign of significant budget slashing for the new fiscal calendar, said Andy Lipow, president of Lipow Oil Associates in Houston.

“The Permian tends to be more resilient, and we might be seeing the impact of producers cutting their new budgets,” Lipow said.

The oil rig count now stands at 516 rigs, down 68 percent from when oil field rigs were operating at the peak of the U.S. oil boom in October 2014, when oil rigs totaled 1,609. The amount of rigs exploring for natural gas also sunk sharply by 14 down to just 148 rigs.

The overall rig count is at it lowest point since 1999. Texas still counts 308 rigs, which is nearly half of the nation’s total of 664 rigs. Louisiana picked up one new rig and it was the only gainer in the country for the week.

The holdouts, essentially, can no longer hold out, said Marshall Adkins, director of energy research at Raymond James in Houston.

“The last bastions of resistance are being ferreted out by the low price of oil,” Adkins said. “It’s rapidly becoming a wasteland.”

The price of oil also continued to sink Friday with the benchmark for U.S. oil settling at $33.16 a barrel, down 11 cents for the day and at its lowest settlement since 2004 on the New York Mercantile Exchange.

“Below $50 the industry doesn’t work, and we’re well below $50,” Adkins said. “Oil prices have been a disaster. At these levels, you’re going to see everyone cut back.”

Rig count and oil production reductions are likely to continue at least through March thanks to the global glut of oil supply, Lipow said, but also because U.S. refiners will soon enter into spring maintenance periods and their demand for crude oil will temporarily decline.

The next three to six months are expected to be ugly, Adkins said, but he is bullish heading into the latter half of the year, and even for 2017 and 2018.

The ongoing U.S. production cuts will eventually put supply and demand back into synchronization, Adkins said. That balance will have a much greater impact than the market’s focus on China’s weakening economy and other concerns, he said.

http://fuelfix.com/blog/2016/01/08/oil-rig-count-plummets-to-start-2016/

Chevron Corp. and PetroChina Co. started natural gas production in China’s southwestern regions of Sichuan and Chongqing, eight years after signing a production-sharing agreement.

Gas well-A in Chongqing’s Luojiazhai gas field began commercial natural gas production on Dec. 30, China National Petroleum Corp., PetroChina’s parent, said in a statement Monday. PetroChina had signed the 30-year agreement with Chevron in 2008, under which the second-largest U.S. oil producer took a 49 percent stake in the parcel and became the operator.

The Luojiazhai project, the first phase of development, will produce 3 billion cubic meters of gas a year, according to the statement. Both parties will work on phase two and three in the same area. The three phases together, known as the Chuandongbei project, cover about 800 square kilometers (309 square miles), according to the statement.

The partners had promised to produce 2 billion cubic meters of gas by 2010 and 6 billion cubic meters by 2013 from the Chuandongbei project, China’s largest onshore oil and gas exploration venture with a foreign partner.

Chevron beat Royal Dutch Shell Plc, Statoil ASA and Total SA to win the right to develop the so-called sour-gas reserves at Chuandongbei. Sour gas refers to natural gas that contains a high level of hydrogen sulphide.

http://www.bloomberg.com/news/articles/2016-01-11/petrochina-chevron-sichuan-gas-project-in-china-starts-output

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Goldman Sachs has diagnosed a new reason for the sudden slump in energy industry sentiment this week: talk of agility, not agony, among leading U.S. shale oil producers speaking at the Wall Street bank's closed-door conference.

In a research note following its Jan. 5-7 Global Energy Conference in Miami, which was closed to the media, the analysts said that investor sentiment "deteriorated further" during the event for three reasons, including a view that drillers were still overly optimistic about the potential for $50 oil.

"Investors felt producers were not being responsive to $35 a barrel WTI (West Texas Intermediate crude oil) by focusing more on their agility versus potential for their production to decline," they wrote.

Unfavorable weather and weakness in the Chinese economy also weighed on sentiment, the analysts said in a note entitled "Are we there yet?". They also said Pioneer Natural Resources' $1.4 billion equity offering this week "increased investor concern that financial stress is insufficient to bring oil markets back into balance".

While the note is focused on energy companies rather than the oil market, it offers a new perspective on the dramatic 10 percent slump in crude prices this week that traders blamed on a variety of other factors, including a dive in the Chinese stock market and a sharp rise in U.S. gasoline stocks.

It also reinforces the core thesis underpinning the bank's ultra-bearish outlook on the oil market. Its market analysts have been warning that a $20 a barrel price shock may be necessary to accelerate the slow-down in drilling and prevent global inventories from overflowing with surplus crude oil.

So far, the U.S. shale oil drillers have proven stubbornly optimistic about the outlook, doing everything they can to maintain output even as cash dwindles and, in the process, feeding the glut that has depressed global prices.

"Investors were looking for fear and trepidation from producers but got agility and below-expected clarity instead," according to Friday's research note.

The analysts said that producers such as Continental Resources Inc, Devon Energy Corp and Marathon Oil Corp had assumed a $50 a barrel price, and indicated they would have to cut back on spending if the forward price curve dropped below that level. The balance of 2016 was trading at around $38 a barrel on Friday.

None of the firms posted any material on their websites by Friday.

It will likely take several more months to see whether the response among drillers would be enough to shore up prices as drillers get into the "mindset" of $40 crude, they wrote.

"At our conference, producers largely did not provide specifics on what capex/ production would look like at $35/bbl oil," they wrote. "Instead, producers spoke largely of their agility to spend within cash flow and ... ramp up when needed."

And when might that be?

"Commentary suggested $50 per barrel WTI is now where producers would raise activity."

http://www.reuters.com/article/us-oilproducers-goldmansachs-idUSKBN0UM2A020160109

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Oversupplied oil and natural gas markets, now coupled with sharply declining oil prices, are setting up a dismal year for capital spending by exploration companies, with domestic operators possibly cutting their spend plans by as much as half from 2015, analysts said this week.


The hope that capital expenditures (capex) by the exploration and production (E&P) sector would increase this year is becoming less likely, one analyst said. The bottom line is simple, he toldNGI's Shale Daily. If commodity prices were to rise, spending would follow, but at current prices, that scenario is tentative at best.

Cowen and Co. LLC this week issued The Original E&P Spending Survey, the signature report by analyst Jim Crandell, who initiated it in 1982. Worldwide capex plans were reviewed for 450 companies, with analysts asking detailed questions about the composition of budgets and strategic shifts. For 2016, it's going to be a slice and dice world for the E&Ps.

"In the U.S., the 185 companies that we surveyed are planning an average decrease in their upstream capital expenditures of 24% to $89.6 billion," Crandell said. "In Canada, we estimate that the 103 companies that we surveyed are budgeting upon a 22% decline.

"The cuts in U.S. E&P spending are broad-based and driven by reduced cash flows and uncertain economics. Under a 24% decline in spending, we estimate the average U.S. onshore rig count will fall by 29% in 2016, to exit the year at 660. We forecast completion activity will drop by 24% for the calendar year of 2016."

Global capex is estimated to decline by 17% this year to $447 billion, but the estimate is based on $48.50/bbl West Texas Intermediate (WTI). International spend is expected to decline by less than in North America.

"We did notice that the companies that were among the later ones to respond to our survey used a bit lower oil prices," Crandell said. "Because of the small difference, we treated Brent the same as WTI."

The latest findings represent the "largest two-year declines" in North American (NAM) and international spending since the survey began more than three decades ago. There are "cutbacks across the board," but "smaller companies are cutting back far more substantially."

Domestic producers whose capex budgets are less than $50 million are reducing spending by an average of 63%, while the largest spenders -- those with budgets of more than $1 billion -- plan to cut spending by 20%. Canadian E&P spend is similar, with overall reductions of 22%. The companies spending under $50 million in Canada now are planning to reduce their budgets by 41% year/year, while the $1 billion-plus spenders see capex down by 19%.

The oil majors whose businesses are concentrated in NAM -- BP plc, Chevron Corp., ExxonMobil Corp. and Royal Dutch Shell plc -- are seen reducing their capex on average by 10% from 2015.

"We forecast a 20%-plus coming from Chevron, but single-digit declines at BP, ExxonMobil and Royal Dutch Shell," Crandell said.

If oil prices were to stay at current levels, more capex reductions are likely. The "most common answer" to Cowen's survey for what average oil price would cause E&Ps to reduce capex was $40/bbl.

"Since we are below these levels going into the year, it seems to us that there is a good chance of further reductions," Crandell said. Most of the E&Ps surveyed (60%) said it would take a $60/bbl oil price to get them to increase spending; 21% said a $55 price would trigger a bump.

Based on the analysis by Cowen colleague Marc Bianchi, "this spending scenario would result in a year-end 2016 rig count of about 660 versus 685 today and an average 2016 rig count of 666 -- down by 29% versus calendar 2015," Crandell said. "The difference is increased capex per rig. Well counts would perform a bit better, down by 24% for calendar 2016.

"Assuming a 30% spending cut, rigs would need to fall by 75, exiting at 610 with well counts down by 28% for the calendar year."

E&Ps have changed their thinking about "important technologies," the Cowen survey noted.

"In recent years it has been a battle between horizontal drilling and fracturing/stimulation for the top spot," Crandell said. "They were joined this year by reservoir recovery optimization. Other notable gainers included deepwater technology and intelligent well completions.

"It should be of no surprise that the majority of companies in every category called the economics of drilling poor. The one surprise was that there were both independents and majors who called the economics of drilling in the U.S. excellent."

Evercore ISI's James West said the E&Ps now are "at oil's mercy." West and his analyst team issued an updated capex forecast this week one month after publishing initial findings -- all because of the decline in oil prices. Evercore's initial survey estimated NAM capex would fall by 19% year/year, with U.S. spend down 20% to less than $100 billion total. Today's projections at today's oil price are grimmer.

"Our initial expectation was formed with E&P companies budgeting WTI prices at $47.60/bbl, roughly 29% above the current spot price and 17% above the current calendar '16 strip price," West said. A "record 74% of operators surveyed originally had selected oil prices as the key determinant of 2016 budgets, followed by cash flow at 59%. In addition, nearly 80% of companies we surveyed are expecting to spend within cash flow this year, up sharply from just 55% in 2015."

More than half of the companies had stated they would decrease spend if WTI "remained below $40/bbl. Given continued weakness in the underlying commodity, we believe initial 2016 NAM budget announcements over the coming one to two months may amount to as much as 40-50% annual reductions -- significantly steeper cuts than forecasted less than one month ago."

Many E&Ps are "largely at the mercy of the commodity with under-hedged books," according to West. Evercore analyst Stephen Richardson recently noted that 2016 hedged crude oil volumes stood at 27% at the end of December for his coverage universe of independent producers, while operators hedged only 6% of 2017 volumes.

"With laser focus on spending within cash flow, initial 2016 upstream budgets are now unlikely to start down just 15-20% in North America as WTI crude oil lingers below $40/bbl," West said.

The "bear scenario would remove an incremental $65 billion of upstream spending this year. Assuming a 45% sequential NAM spending decline and a 15% international spending decline, global upstream capex would post a 23% year/year decline during 2016 compared to our initial forecast for a global spending decline of 11%," which could "effectively remove an additional $65 billion of global upstream spending from this year's market.

"However, as oil market fundamentals likely improve heading into second half of 2016, we think upward revisions to budgets, particularly for North America, should unfold. One caveat is that consolidation among the majors, which is increasingly likely in a more sustained low oil price environment, could present risks to increased overall spending levels."

Whichever way the energy industry considers 2016, it looks to be a challenging year, said U.S. Capital Advisors analysts Cameron Horwitz and Omar Zakaria. The "pain trade has to spill over into the New Year. We think '16 will be a period of capitulation, marked by the rationalization of high-cost supply sources that are no longer needed and a broad-based hunkering down of even the best asset/strongest balance sheet operators."

The first six months "will invariably be painful," they said. However, with "massive efficiency gains and cost structure improvements, we see E&Ps with core asset bases coming out of the '16 abyss in position to more competently compete for global market share."

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Last month I wrote about soaring profits for resource companies working in Argentina. With local costs for such firms plunging following the devaluation of the Argentinean peso.

And this week the government here confirmed this as one of the best crude markets going on the planet.

That’s because of the oil price in the country. Which officials said will be fixed at US$67.50 per barrel for 2016.

Unlike most global oil markets, Argentina currently mandates oil sale prices — to provide profitability for drillers and ensure development of domestic oil fields and security of local supply.

That means Argentina’s oil producers will be seeing some of the highest revenues going anywhere in the world.

The government did say it may adjust the price throughout the coming year — with this week’s announced price being a 10 percent decrease from the $75 per barrel price that prevailed across Argentina in December.

But even a few more cuts of that magnitude would still leave Argentina’s oil market as the best on the planet. By far.

The high oil price is especially good news in the wake of the recent peso devaluation. Which should push down costs for labor and local supplies for E&P firms — further ramping up profits.

Combine that with recent successful work in Argentina’s emerging Vaca Muerta shale oil and gas play, and it looks like this may be the world’s best spot in the petroleum business today. Watch for financial statements from firms producing here to see if profits are super-charging over the coming months.

http://oilprice.com/Energy/Oil-Prices/Oil-Producers-Here-Are-Now-Getting-Double-The-World-Price.html

On Friday, the kingdom confirmed it's mulling plans to sell a stake in the company. Here’s the official statement:

Saudi Aramco confirms that it has been studying various options to allow broad public participation in its equity through the listing in the capital markets of an appropriate percentage of the Company’s shares and/or the listing of a bundle its downstream subsidiaries.

Once the study of these various options is complete, the findings will be presented to the Company’s Board of Directors which will make its recommendations to the Saudi Aramco Supreme Council.

This proposal is consistent with the broad and progressive direction pursued by the Kingdom for reforms, including privatization in various sectors of the Saudi economy and deregulation of markets, which the Company strongly supports.

Saudi Aramco would like to emphasize that this process will strengthen the Company's focus on its long term vision of becoming the world’s leading energy and chemical enterprise. This includes prudently managing the Kingdom’s hydrocarbon resources, adding value across the value chain, reliably meeting its customers’ demand, and meeting its stakeholder and environmental commitments.

As we noted before, "Aramco has the largest known oil reserves at around 261bn barrels – almost 10 times more than Exxon Mobil."

In order to get an idea of the sheer magnitude, consider the following chart which shows that when it comes to crude, no one does it like Riyadh:

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