The Douglas Channel LNG Consortium, led by Canadian AltaGas, said on Thursday it will halt further development of its floating LNG export project in British Columbia due to unfavourable market conditions.

The consortium, which includes Japan’s Idemitsu, EDF Trading of France and Exmar of Belgium, had planned to achieve a final investment decision on the small-scale LNG project by the end of 2015.

However, the “worsening global energy price levels and a challenging market environment have caused the consortium to withdraw from the project,” Douglas Channel LNG said in a statement.

Canadian National Energy Board issued a licence in January to Douglas Channel LNG project to export up to 10.3 billion cubic metres of natural gas per annum for a period of 25 years.

The plans for the LNG project included a barge-based 0.55 mtpa LNG facility with natural gas sourced from Western Canada and transported to the project site at District Lot 99, near Kitimat, British Columbia for liquefaction.

http://www.lngworldnews.com/canada-douglas-channel-lng-project-shelved/

China's natural gas consumption rose 17.6 percent in January from the same month last year, reaching 22.3 billion cubic metres, China's central state planning commission said on Friday.

Production was up 4.1 percent on the year to 13.1 bcm, the National Development and Reform Commission (NDRC) said in a statement on its website.

Refinery runs of crude oil fell 1.8 percent on the year in January to 38.66 million tonnes, or 9.1 million barrels per day. Crude output dropped 2.1 percent to 17.69 million tonnes, or 4.17 million bpd.

The country's National Bureau of Statistics does not release standalone production figures for January.

Its production figures generally differ from those released by the NDRC.

http://en.chinamining.com.cn/News/2016-02-26/1456465077d75425.html

Exxon Mobil Corp. may lose its top-notch credit rating from Moody’s Investors Service as the oil-market collapse imperils cash flow needed to cover debt payments and investment in new discoveries.

Seven of the other largest U.S. energy explorers also were put on notice or downgraded by Moody’s Thursday after the rating company concluded crude prices will remain weak for years. The Moody’s review featured a Who’s Who of American oil and gas heavyweights, from Chevron Corp. to Marathon Oil Corp. to ConocoPhillips.

The outlook for Exxon, which has held Moody’s top Aaa rating for more than 90 years, dropped to negative from stable, the rating company said in a statement on Thursday. The move followed a warning earlier this month from Standard & Poor’s that its own rating on Exxon’s debt may be in jeopardy.

"The negative outlook reflects our expectations of negative free cash flow and weak cash flow based leverage metrics,” Moody’s said. "While the company is cutting its capital spending and operating costs in response to lower commodity prices, this diminished level of capital reinvestment could adversely affect Exxon Mobil’s reserve replacement and production profile in the latter part of this decade."

Triple-A Edge

Exxon, which traces its roots to the 1800s when kerosene began competing with whale oil as household lamp fuel, has annual revenues that dwarf the economies of most of the nations in which it operates. The Irving, Texas-based company’s platinum credit rating gives it an edge in competing with rival drillers when negotiating exploration concessions with oil-rich nations, Chairman and Chief Executive Officer Rex Tillerson has said.

“Exxon Mobil places a high value on its strong credit position and continues to be focused on creating long-term shareholder value despite near-term market volatility,” Scott Silvestri, an Exxon spokesman, said in an e-mailed statement on Thursday.

Credit rating firms have been downgrading drillers, explorers and even entire nations as the oil-price crash erases revenue relied upon to pay debts and fund day-to-day operations. The downgrades have spanned from U.S. shale fields to offshore Brazil. Deep cuts to headcounts and exploration spending haven’t been enough to shield balance sheets from the impact of slumping prices.

http://www.bloomberg.com/news/articles/2016-02-25/exxon-has-aaa-rating-affirmed-by-moody-s-with-negative-outlook

Oil futures closed higher Thursday following an afternoon surge on reports of a March meeting between OPEC members and Russia to discuss production.

Venezuela's Oil Minister Eulogio Del Pino said a meeting was scheduled for March that includes Russia, Saudi Arabia, Venezuela and Qatar, several media outlets reported.

Russia's Energy Minister Alexander Novak also referred Thursday to a producers' meeting in March.

"As far as we understand, OPEC countries are planning a meeting of OPEC and non-OPEC ministers in mid-March," Novak was quoted by the Prime news agency as saying.

Saudi Arabia, Venezuela, Qatar and Russia -- agreed to freeze production at January levels, if other key producers did the same.

Oman, which is not an OPEC member, is willing to cut output by 10% if a deal is reached between major OPEC and non-OPEC producers, Oil and Gas Minister Mohammed al-Rumhy said, according to the Oman Observer.

Oman's crude and condensate output averaged more than 1 million b/d in January, so a 10% cut would remove 100,000 b/d from the global market.

http://www.platts.com/latest-news/oil/newyork/oil-futures-strengthen-after-late-report-of-producer-21000270

Oil exports from the autonomous Kurdish region in northern Iraq have been suspended for a second week after pipelines were sabotaged in conflict-hit southeastern Turkey, Reuters reported.

Halting the oil exports - Iraqi Kurdistan's main source of income - will deprive the region of much-needed revenue, already reeling from record-low oil prices and an oversaturated market.

The pipeline, which carries about 600,000 barrels of crude per day from the fields in Iraq to Turkey's Ceyhan port, is set to remain closed until Feb. 29, meaning an outage of nearly two weeks since pumping stopped on Feb. 17.

Industry sources have indicated the pipeline was sabotaged. Violence has flared in Turkey's mostly Kurdish southeast, as skirmishes between the Turkish military and Kurdistan Workers' Party (PKK) militants have led to a deteriorating security situation.

The pipeline has been sabotaged several times inside Turkey, with the Kurdish government in Iraq accusing the PKK of targeting it. Although both the KRG and PKK are Kurdish, the PKK opposes the KRG's economic relations with Turkey.

As a result of the outage, Iraq's state-run North Oil Company (NOC) which operates the fields in Kirkuk, has reduced its production from 200,000 barrels per day to about 120,000.

http://www.albawaba.com/news/kurdish-oil-exports-suspended-after-pipeline-sabotaged-turkey-809222
 

Petrobras’ dominant position in the highly-productive pre-salt province off Brazil could be challenged after the country’s Senate passed a bill that could pave the way for other players to become operators of acreage there.

http://www.upstreamonline.com/live/1425192/brazil-senate-passes-pre-salt-rule-change-bill?utm_source=twitterfeed&utm_medium=twitter

Brazil's state-led oil company Petrobras is expected to fetch as much as $6 billion from the sale of a natural gas pipeline unit in Brazil's industrialized southeast, the Valor Economico daily newspaper reported on Thursday.

Bids of between $5 billion and $6 billion for Nova Transportadora do Sudeste are expected by a Tuesday deadline from Canadian, French and Chinese companies, the paper said, without citing the source for its information.

Potential bidders include Canada's Brookfield Asset Management Inc (BAMa.TO), China National Petroleum Corp [CNPET.UL], and a joint venture between the CanadianPension Plan Investment Board [CPPIBC.UL] and France's Engie SA (ENGIE.PA), Valor reported.

Petroleo Brasileiro SA, as the oil company is formally known, has plans to sell about $14 billion of assets this year in an attempt to cut its debt and maintain cash amid a plunge in world oil prices and a corruption scandal at the company.

Petrobras' estimated $130 billion of debt is the largest in the oil industry and one of the largest of any industrial company in the world.

A Brookfield press spokesman in Toronto declined to comment when contacted by Reuters. Engie's press office in Rio de Janeiro declined to comment. A Canadian Pension Plan Investment Board press official in Toronto declined to comment. CNPC officials did not immediately respond to an emailed request for comment.

https://twitter.com/search?q=petrobras&src=typd

U.S. crude futures were down 2 percent on Thursday, extending losses from earlier in the session, after data showing stockpiles at the Cushing, Oklahoma hub for U.S. crude deliveries having reached new record highs.

The front-month in U.S. crude futures was down 63 cents at $31.52 a barrel by 10:08 a.m. EST (1508 GMT).

It hit a session bottom of $31.32 after market intelligence provider Genscape said inventories at Cushing rose by more than 503,000 barrels to reach above 67.5 million barrels between Feb 19 and Feb 24, traders who saw the data said.

http://www.reuters.com/article/oil-markets-cushing-idUSL3N163661

Sanchez Energy Corporation, today announced the Company's operating and financial results for the fourth quarter and full-year 2015, which included the following highlights:

HIGHLIGHTS FOR FOURTH QUARTER OF 2015

- Record production of 5.3 million barrels of oil equivalent ('MMBoe')
- Record quarterly average daily production of 58,115 barrels of oil equivalent per day ('Boe/d')
- Better than expected production results were driven by Catarina production of 46,030 Boe/d, the highest quarterly production level recorded to date from the asset, as well as strong performance from new wells in the Cotulla area
- Average quarterly well costs at Catarina of $3.5 million per well and wells are 40 percent more productive since first acquired
$435 million cash balance at year-end 2015 and $735 million in total liquidity
- Closed the Western Catarina Midstream Divestiture for approximately $345 million in cash
- Entered a joint venture with Targa Resources Partners LP ('Targa') to construct a cryogenic processing plant and high pressure gathering pipeline near Catarina, which is expected to provide a path to improved yields, lower processing fees, and significant marketing benefits

HIGHLIGHTS FOR FULL-YEAR 2015

- Record annual production of 19.2 MMBoe for an average annual production rate of 52,560 Boe/d, an increase of 72% over 2014 production
- Record oil production averaging 19,629 barrels per day ('Bbl/d')
- Upstream capital expenditures including accruals of $545 million in 2015 compared to $867 million in 2014, a reduction of approximately 37% over 2014
- $155 million mark-to-market value of hedging position at year-end 2015 corresponding to hedge contracts covering approximately 82% of expected 2016 revenues, and $189 million current mark-to-market value of hedge position as of February 24, 2016
- Completed the 50-well annual drilling commitment at Catarina for the period July 1, 2015 through June 30, 2016, which provides the Company with significant operational and financial flexibility in 2016 and 2017, as up to 30 wells drilled in excess of the minimum commitment can be carried forward to the next annual period
- 2015 year-end proved reserves are approximately 128 MMBoe, with a PV-10, a non-GAAP measure defined below, of $594 million

MANAGEMENT COMMENTS  

2015 was a strong year for Sanchez Energy despite the most challenging commodity environment we have faced as a Company,' said Tony Sanchez, III, Chief Executive Officer of Sanchez Energy. 'Our achievements in 2015 include ending the year with a strong cash position of $435 million. The Company's cash position was aided by several key divestitures with Sanchez Production Partners which generated approximately $430 million in cash proceeds without needing to issue additional equity or debt. Our balance sheet remains strong and we are well prepared to weather a prolonged down cycle.'

http://www.oilvoice.com/n/Sanchez-Energy-announces-fourth-quarter-and-full-year-2015-results/784b7300ae2f.aspx

At least 163 tankers.

That’s how many cargoes of natural gas it’d take to wipe out the ever-expanding glut of the heating and power-plant fuel in the U.S. A mild winter and production still flowing out of America’s shale formations have inventories swelling compared with previous years, dragging down U.S. gas prices even as the first export of shale gas prepares to leave from Cheniere Energy Inc.’s Sabine Pass terminal in Louisiana today.

“Production keeps going and right now we are pricing in a natural gas-ageddon,” said Phil Flynn, senior market analyst at Price Futures Group in Chicago. “How many tankers do we need to to get rid of the glut?”

In a testament to how massive America’s natural gas supplies have become (they’re near a seasonal record), it’d take at least 163 tankers the size of the Asia Vision, the vessel at Cheniere’s docks, to bring U.S. gas inventories back to the five-year average. If you lined them up end to end, they would stretch about 30 miles (48 kilometers), just long enough to ring the perimeter of Manhattan.

And the chances of this fleet suddenly showing up to whisk U.S. gas away are slim. Initial exports will be too small to make a dent in the U.S. supply surplus anytime soon, said Jason Schenker, president of Prestige Economics LLC in Austin, Texas.

“It’s hard to find much of a bullish story,” Schenker said. “We see low natural gas prices for the balance of this year.”

http://www.bloomberg.com/news/articles/2016-02-24/how-many-gas-exports-are-needed-to-wipe-out-the-glut-163-ships

Iran is offering to swap exports of crude oil for imports of refined fuel as some European customers are unable to find banks to process payments, a sign the Middle Eastern nation is still struggling to regain markets since the removal of sanctions.

The National Iranian Oil Co. is resorting to barter because financial restrictions still impede trade, said three officials who asked not to be named citing company policy. Hellenic Petroleum SA, the Greek refiner that got as much as quarter of its crude from Iran before the European Union embargo, can’t secure deliveries because banks won’t process payments, said two people familiar with the matter.

Iran is seeking to regain lost European markets and boost exports to Asia after sanctions were removed last month upon completion of an agreement limiting its nuclear program. It loaded its first cargo of oil to Europe since 2012 this month onto a tanker chartered to French oil company Total SA. The Persian state plans to increase exports by 1 million barrels a day this year, according to Oil Minister Bijan Namdar Zanganeh.

Cautious Banks

Banks are being “super cautious because they do want to have access to the U.S. markets and the U.S. rules as to what they can do aren’t particularly clear,” said Ross Denton, a partner at Baker & McKenzie LLP specializing in sanctions. “Iran is open for trade” only for entities with no direct connection to the U.S., he said.

Several European banks approached by Hellenic have refused to handle transactions linked to Iran, the two people said, asking not to be identified because the matter was private. This has stymied the company’s Jan. 22 agreement to resume purchases of Iranian crude.

Barter deals avoid the need to access bank finance for as long as many lenders remain unwilling to issue letters of credit for Iran-linked trades, the three NIOC officials said. The company is asking for at least partial cash payment for most refined-product trades and accepting transactions in Euros and other currencies, they said. It is offering products such as fuel oil in exchange for imports of gasoline and is also willing to swap crude for fuel, they said.

Even after the successful nuclear deal, some U.S. sanctions on Iran remain in place. In 2014, the nation’s regulators imposed fines on some European banks including BNP Paribas SA for processing transactions to nations under U.S. sanctions like Iran, Cuba and Sudan.

http://www.bloomberg.com/news/articles/2016-02-25/iran-seeks-oil-barter-deals-as-european-buyers-face-bank-hurdles

Russian energy giant Gazprom has reduced natural gas supplies to private sector companies in Turkey by 10 percent due to a price dispute, officials at Turkey's energy ministry told Reuters on Thursday.

The cut came after Turkish companies refused to pay a fresh bill sent by Gazprom with higher prices after an initial deal between Ankara and Moscow envisaging a 10.25 percent reduction in prices was cancelled.

Russia's Interfax news agency said the cut came into effect on Feb. 10. Six private Turkish companies buy a total of 10 billion cubic meters of natural gas from Russia annually.

Turkey is dependent on Russia for more than half of its natural gas imports but the two countries have been at loggerheads since November when Ankara downed a Russian warplane along the Turkey-Syria border saying it violated its air space.

Turkey has not asked for additional supplies from elsewhere, an industry source said, as demand at the moment remained low due to warm weather. "At the moment there are no problems in terms of meeting the gas demand," he said.

Turkey said last year it had struck a deal giving it a 10.25 percent price discount on gas from Gazprom, but a final signing was delayed, prompting state pipeline operator Botas to appeal to the International Chamber of Commerce (ICC).

Russia is Turkey's largest gas supplier with sales of 28-30 billion cubic metres annually worth around $6.5 billion. Turkey imports 60 percent of its gas and 35 percent of its oil from Russia.

http://www.reuters.com/article/russia-gazprom-turkey-prices-idUSL8N1644K9

Sunoco Logistics Partners LP, which operates pipelines and terminals, is poised to export the first U.S. waterborne ethane cargo “within a week,” according to Genscape Inc.

The company’s Mariner East 1 pipeline, which stretches from the Marcellus shale deposit in western Pennsylvania to the Marcus Hook terminal on the Delaware River near Philadelphia, boosted ethane deliveries on Feb. 22, said Amanda Townsley, senior adviser of petrochemicals and LNG for Genscape, which is monitoring the line.  The jump in flows coincides with the arrival of the terminal’s first tanker, the JS Ineos Intrepid, at the ethane dock, she said.

This ethane is contracted to go to Norway as feedstock at processing plants owned by Ineos Europe AG, and will ultimately be used to make products such as plastic. U.S. producers have seen prices for natural gas and liquids tumble as output from shale deposits outpaces demand.

“The first ship at the ethane dock is exciting; this would be the first waterborne export from the U.S. period,” Townsley, based in Houston, said in a telephone interview. “It’s not a massive volume so it’s not a game changer for the supply and demand balance, but it’s a big deal for the producers in the area.”

Range Resources Corp. is contracted to ship 20,000 barrels of ethane on the pipeline to the Philadelphia area terminal, according to its website. Ineos previously announced it also has a long-term contract to purchase ethane from Consol Energy Inc.

Sunoco Logistics spokesman Jeffrey Shields declined to provide updates and said to listen to the company’s earnings call early Thursday for any developments, according to an e-mail Tuesday. He didn’t respond to requests for comment on Wednesday.

http://www.bloomberg.com/news/articles/2016-02-24/sunoco-may-ship-first-u-s-waterborne-ethane-export-within-days

China has asked local governments in 11 provinces to ban in urban areas the selling of high-sulphur diesel that is used for industrial and farming purposes rather than in automobiles, Beijing said in a policy document released on Thursday.

The request comes after China rolled out "national five" standards for gasoline and diesel on Jan. 1 in the 11 provinces in the more economically developed eastern part of the country. The standards are equivalent to Euro V specifications that allow a maximum sulphur content of 10 parts per million (ppm).

Due to lax supervision, however, "general diesel" or diesel with a high-sulphur content is still being sold at urban petrol stations in the provinces that come under the new policy, said the National Development & Reform Commission (NDRC) on Thursday in thedocument posted on its website www.ndrc.gov.cn.

Only kiosks in rural areas or along the rivers should be allowed to sell high-sulphur diesel, the NDRC said.

The tighter fuel standards are an attempt to tackle air pollution. Emissions from automobiles, especially from diesel-burning trucks, are one of the main contributors to the choking smog that plagues many Chinese cities.

"Along with China's accelerating fuel upgrades, the problem of having the lower-grade fuel quit the market has become increasingly prominent," the agency said.

"Especially as general diesel is being sold to automobiles illegally, marketing of (higher quality) automotive diesel has been adversely affected."

The agency requires all service stations to mark clearly the names and quality of their fuels to help motorists select the grades they want and to allow authorities to supervise fuel quality, the NDRC said.

By January 2017, "national five" will cover the whole country, it said, in line with an announcement last April that moved the roll-out up by one year.

Refiners have started boosting output of cleaner fuels, and also raised imports of diesel to 145,000 tonnes in January as recorded by customs data, despite an overall domestic surplus that has turned China into a leading exporter of the fuel.

Traders said the rare imports, which were about 20 percent of the diesel China exported last month, were driven in part by the need to meet the cleaner fuel standards.

China, the world's largest fuel user after the United States, has more than 90,000 petrol stations. Nearly 60 percent of them are owned or run by dominant state refiners Sinopec Corp and PetroChina, the rest by smaller state oil companies like Sinochem Corp [SASADA.UL] and independents.

The big state refiners say they have spent billions of dollars upgrading facilities to make the cleaner fuels.

http://www.reuters.com/article/us-china-fuel-quality-idUSKCN0VY0Z5

The best option for privatizing top Russian oil producer Rosneft is to sell the state's 19 percent stake to a strategic investor "to receive a maximum premium", Russian news agencies quoted Kremlin aide Andrei Belousov as saying on Thursday.

http://www.reuters.com/article/us-russia-privatisation-rosneft-idUSKCN0VY0XQ

Technip's shares jumped by more than 15 percent on Thursday as markets applauded its fourth-quarter results and it said that its 2016 dividend was well covered thanks to a strong backlog of projects while cash flow helped it to resist the worst of the oil price rout.

Although the French oil services company expects business to dip in 2016 as oil and gas companies hold off on new investments, it said it expects to some rebound in momentum from late in the year going into 2017.

Kepler Cheuvreux analysts, who have a "hold" rating on Technip, wrote that the results were in line with forecasts and that they expect the company to announce a multibillion-euro contract in Mozambique in the coming weeks.

Italy's Eni said on Wednesday that it had won approval from the Mozambique government to build its planned Coral floating liquefied natural gas (LNG) plant. Technip is expected to take part, but a company spokesman was not immediately available to comment.

One London-based analyst described Technip's outlook as reassuring, while Jefferies, which has a "buy" rating on the stock, said the results were above consensus and 2016 guidance was positive.

SUPPLIERS SQUEEZED

Sector suppliers have been squeezed along with oil and gas companies that have cut spending and jobs, while placing projects on hold, in response to a 70 percent drop in oil prices since mid-2014 because of a global crude glut.

Technip's Italian rival Saipem said on Wednesday that it may have to cut costs further to meet a commitment to stick to profit forecasts for 2016 after it posted a 2015 net loss of 806 million euros and wrote off assets.

The Technip CEO, Thierry Pilenko, told reporters that a strong backlog of work, solid cash flow and cost cuts had enabled the firm to remain resilient.

"We have a very robust balance sheet, which is supported by a strong cash generation and a solid backlog that allows us to set very clear objectives for 2016," Pilenko said.

Technip said its business backlog was 17 billion euros ($18.7 billion) at the end of 2015, compared with more than 20 billion euros the previous year, and that it ended the year with 1.9 billion euros of net cash.

The company's cost savings target has been increased to 1 billion euros by 2017, from the 830 million euros announced last July, but it said no further job cuts are planned.

Pilenko said the company might consider small acquisitions and alliances to strengthen its position in technological developments.

The company's chief finance officer told analysts that the dividend for 2016 is well covered.

http://www.reuters.com/article/technip-results-idUSL8N1640T7

Repsol SA, the worst-performing major European oil stock over the past year, cut its dividend for the first time since 2009 as its acquisition of Talisman Energy Inc. turned sour amid the crude-market rout.

Repsol’s board proposed cutting the final 2015 payout to 0.3 euros per share from 0.5 euros as the Madrid-based producer followed Eni SpA and ConocoPhillips in paring its dividend. The company booked an impairment charge of 2.96 billion euros ($3.26 billion) for the collapse in prices.

Repsol has lost half its market value over the past year, the most among Europe’s six largest oil companies, as it struggles to convince investors of its ability to weather the slump in crude while integrating Talisman. The assets of the Canadian company it acquired for $13 billion last May suffered operating losses in Norway, Colombia and North America.

The company reported a net loss of 2.06 billion euros in the fourth quarter. Talisman assets posted a 208 million-euro operating loss, even as Repsol’s production unit showed an operating profit of 11 million euros. Adjusted net income rose 25 percent to 461 million euros from a year earlier, beating the average 451.1 million-euro estimate of seven analysts surveyed by Bloomberg.

Repsol’s shares rose 1.9 percent in Madrid trading as the 22 member STOXX Europe 600 Oil & Gas Index gained 1.8 percent.

The company plans to sell 6.2 billion euros of assets by 2020 to cut its debt load from the highest in at least 27 years. Net debt rose sixfold to 11.9 billion euros as of Dec. 31 from a year earlier following the Talisman acquisition.

Repsol cut its dividend for the first time since reducing the payout on its 2009 earnings as it struggles to avert credit rating downgrades and seeks to avoid selling down its 30 percent stake in Gas Natural SDG SA. Repsol last month doubled its annual target for synergies from the Talisman acquisition to $400 million.

The company reported that refining margins, a gauge of profitability, rose to $7.3 per barrel in the fourth quarter from $5.5 per barrel a year ago. Repsol pumped about 697,500 barrels of oil equivalent per day in the three months through Dec. 31, compared with 371,000 a year earlier, before the takeover of Talisman.

Repsol announced the sale of its U.K. offshore wind production unit to SDIC Power Holdings Co. for 238 million euros, giving an after tax capital gain of 109 million euros.

http://www.bloomberg.com/news/articles/2016-02-25/repsol-cuts-dividend-after-booking-charge-for-crude-price-slump

Leviathan partners raise annual natgas production forecast

The partners developing Israel's massive Leviathan offshore natural gas field increased their annual production forecast on Thursday and said they expect to bring the project online by the end of 2019.

The group led by Texas-based Noble Energy and Israeli conglomerate Delek Group presented a new development plan that calls for 21 billion cubic meters (bcm) of gas production each year, up from 16 bcm in their initial plan.

They also lowered the estimated cost of the project to $5-$6 billion from a previous $6-$7 billion.

Leviathan was discovered in 2010 in the eastern Mediterranean and has estimated reserves of 622 bcm, making it one of the world's largest finds of the past decade. But development has been held up due to regulatory uncertainty in Israel.

The government recently agreed to a framework deal with Noble and Delek to speed up development of Leviathan, though the Supreme Court needs to give a final approval because some opponents have claimed it is unlawful.

The development plan presented on Thursday includes drilling eight wells to be connected by a subsea pipeline to an offshore platform, producing a total of 21 bcm a year.

One exit point capable of handling up to 12 bcm a year will be for Israel, as well as bringing supplies to neighbouring markets in the Palestinian Authority, Jordan and Egypt. A second exit point to handle up to 12 bcm is solely for export.

"We are moving forward as fast as possible to bring gas to market by the end of 2019," Yossi Abu, chief executive of Delek subsidiaries Delek Drilling and Avner Oil Exploration , told Reuters.

http://www.reuters.com/article/israel-natgas-leviathan-idUSL8N1642ZG

Western Gas Partners LP has agreed to buy a majority stake in Anadarko Petroleum Corp.’s south Texas oil and gas pipeline system for $750 million.

The deal is for Springfield Pipeline LLC, which owns a 50.1 percent share in the overall gathering system in the Eagle Ford shale basin. The system serves Anadarko and its partners’ production there, Western Gas said in a fourth-quarter earning statement after the close of New York trading Wednesday.

“With the support of Anadarko and the strength of our portfolio, we believe we can continue to deliver meaningful distribution growth even in this commodity price environment,” Western’s chief executive officer, Don Sinclair, said in the statement.

The Springfield system includes 548 miles of gas-gathering lines with a capacity of 795 million cubic feet a day; 241 miles of oil-gathering lines with a capacity of 130 million barrels a day; 24 compressor stations; 260,000 barrels of oil storage; and 75,000 barrels a day of “stabilization capacity.”

Western plans to finance the deal with $449 million of 8.5 percent perpetual convertible preferred units to First Reserve Advisors LLC and Kayne Anderson Capital Advisors LP at a price of $32 per unit. It also will issue 1.25 million Western units to Anadarko and almost 836,000 units to Western Gas Equity Partners LP at $29.91 per common unit. It’s borrowing $247.5 million on its credit line, the company said.

The transaction is expected to close by March 15, Western Gas said.

http://fuelfix.com/blog/2016/02/24/anadarko-selling-majority-stake-in-a-pipeline-system/

Continental Resources, a top producer in the Bakken shale formation, said Wednesday it has ceased fracking operations there amid the continued slump in oil prices.

The bellwether shale company had already planned to defer most Bakken completions in 2016. It has four operated drilling rigs in the North Dakota Bakken with plans to maintain that level through the year.

But Continental said it currently has “no stimulation crews deployed in the Bakken.”

Continental posted an adjusted net loss of 23 cents per share in Q4, down from a profit of $1.14 per share a year ago. Analysts polled by Thomson Reuters were expecting a loss of 21 cents per share. Revenue sank 55.6% to $575.5 million, above views for $568.2 million.

But Continental was bullish on acreage in its STACK play in Oklahoma, and expects an average estimated ultimate recovery of 1.7 million barrels of oil equivalent per well.

“Our overpressured Meramec wells in STACK are delivering some of the highest returns in the Company,” said COO Jack Stark in a statement. “We clearly have another high impact, long-term platform for growth underlying our 155,000 net acres of leasehold in STACK.”

The company plans to average four-to-five operated drilling rigs in the STACK play in 2016.

Last month, Continental guided 2016 capital spending to $920 million, down 66% from 2015. It also sees production falling during the year on lower drilling and well completion activity.

http://www.investors.com/news/shale-producers-post-q4-losses-see-production-rates-falling/

Enbridge Inc. plans to raise C$2 billion ($1.5 billion) in a share sale to shore up its finances in the midst of an oil price rout.

The Canadian pipeline company agreed with a group of lenders to issue 49.14 million common shares from treasury in a so-called bought deal, according to a statement. The funds will be used to pay short-term debt, the company said.

Canadian energy companies face a wave of debt maturities over the next five years that could make it challenging for them to access financing as investors drive up borrowing costs and shun commodities-related debt. Oil has plunged about 70 percent since mid-2014, sapping revenue.

Enbridge’s sale follows two other bought deals in the past week.Whitecap Resources Inc. and Raging River Exploration Inc. both raised C$95 million in the past week through equity raises of their own to pay down debt and fund capital expenditures.

Enbridge’s profit rose in the fourth quarter as record oil shipments on its main system have so far shielded the pipeline operator from the oil rout. While oil and gas producers have been reeling from the collapse of energy prices, firing workers and cutting costs, pipeline fees have provided a steadier source of income. Lines such as Enbridge’s Flanagan South and Seaway Twin have expanded Canadian crude shipments to the U.S. Gulf Coast, and the company also plans to expand in Colombia and Australia.

http://www.bloomberg.com/news/articles/2016-02-24/enbridge-plans-to-raise-c-2-billion-in-equity-sale

Marvin Odum is stepping down as head of Royal Dutch Shell's U.S. operations by mutual agreement, said the Anglo-Dutch oil company, which also announced plans to scrap a major division after abandoning two big North American projects.

Following Odum's departure at the end of March, Shell will abolish its unconventional resources division, which he also headed, the company said in a statement on Wednesday.

The decision to shutter the division marks a rapid change within Shell's organization. In November, it announced a major restructuring of its oil and gas production, or upstream, business starting this past January as part of the integration of BG Group, which Shell acquired earlier this month. Under the new structure, unconventional resources was set to be one of three upstream divisions.

Shell's unconventional Athabasca Oil Sands Project and the Scotford Upgrader in Canada will now join the global downstream organization under John Abbott. The U.S. Shale Resources business will join the global upstream organization under Andy Brown.

The company said the decision would simplify its structure.

Bruce Culpepper, executive vice president HR for unconventional resources and regional coordination, will replace Odum as chairman of U.S. operations.

Odum, who was born in 1958, plans to pursue other opportunities after 34 years with Shell, a company spokesman said.

Odum's departure comes months after Shell ceased its controversial exploration in Alaska's Arctic Sea and suspended the 80,000-barrel-per-day Carmon Creek thermal oil sands project in Alberta, Canada.

"Marvin has had a long and distinguished Shell career, and I'm grateful to him for the central role he's played in the company's success," Chief Executive Officer Ben van Beurden said.

http://www.reuters.com/article/shell-moves-idUSL2N1631BA

Italian energy giant Eni said on Wednesday that the Mozambique government had approved the plan of development for the company’s Coral FLNG project.

The approval relates to the first phase of development of 5 trillion cubic feet of gas in the Coral discovery, located in the Area 4 permit.

The giant discovery, located approximately 80 kilometers offshore of the Palma bay in the northern province of Cabo Delgado, is estimated to contain around 16 trillion cubic feet (TCF) of gas in place.

The plan of development, the very first one to be approved in the Rovuma Basin, foresees the drilling and completion of 6 subsea wells and the construction and installation of a floating LNG facility, with the capacity of around 3.4 MTPA, Eni said in a statement.

“Today’s approval of the Coral plan of development is a historical milestone for the development of our discovery of 85 TCF of gas in the Rovuma Basin. It is a fundamental step to progress toward the final investment decision of our project which envisages the installation of the first newly built floating LNG facility in Africa and one of the first in the world,“ Eni’s CEO, Claudio Descalzi said.

Eni is the operator of Area 4 with a 50% indirect interest, owned through Eni East Africa (EEA), which holds a 70% stake of Area 4.

The other partners are Galp Energia, Kogas and Empresa Nacional de Hidrocarbonetos (ENH) with a 10% stake each. CNPC owns a 20% indirect interest in Area 4 through Eni East Africa.

http://www.lngworldnews.com/eni-secures-approval-for-coral-flng-project-in-mozambique/

Chesapeake Energy terminated 4Q call 30 mins in, many key topics left uncovered

@zerohedge

U.S. crude oil refinery inputs averaged 15.7 million barrels per day during the week ending February 19, 2016, 163,000 barrels per day less than the previous week’s average. Refineries operated at 87.3% of their operable capacity last week. Gasoline production increased last week, averaging 10.0 million barrels per day. Distillate fuel production decreased last week, averaging over 4.4 million barrels per day.

U.S. crude oil imports averaged 7.8 million barrels per day last week, down by 117,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged about 7.8 million barrels per day, 7.0% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 566,000 barrels per day. Distillate fuel imports averaged 242,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 3.5 million barrels from the previous week. At 507.6 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 2.2 million barrels last week, but are well above the upper limit of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 1.7 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 3.7 million barrels last week but are well above the upper limit of the average range. Total commercial petroleum inventories decreased by 5.0 million barrels last week.

Total products supplied over the last four-week period averaged over 19.6 million barrels per day, up by 0.2% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.1 million barrels per day, up by 5.2% from the same period last year. Distillate fuel product supplied averaged about 3.5 million barrels per day over the last four weeks, down by 16.0% from the same period last year. Jet fuel product supplied is up 5.3% compared to the same four-week period last year.

Cushing +333K, Exp. -100K

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

                                                        Last Week   Week Before   Last Year

Domestic Production '000.....   9,102             9,135           9,285

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

---

Attached Files

Oil prices are likely to remain under pressure this year as Saudi Arabia and Iran compete for market share in weak or slowing Asian economies, the editor of The Schork Report said Wednesday.

Stephen Schork said he does not necessarily agree with forecasts that oil will rebound into the $40s in the next 12 months, citing Saudi oil minister Ali Al-Naimi's comments on Tuesday that OPEC and non-OPEC members will not cut production.

"If you are long oil, get it through your head. Saudi Arabia is not going to throw you a life preserver," he told CNBC's "Squawk Box."

Al-Naimi's remarks at IHS CERAWeek in Houston sent oil prices spiraling on Tuesday after futures had risen in previous sessions, bolstered by a plan put forward by Saudi Arabia and Russia to cap output at January levels. That plan would be contingent on participation from OPEC and non-OPEC members.

Saudi Arabia in November 2014 led OPEC's policy of letting the market determine the oil price, rather than cutting production to boost prices.

Schork said it is simply unlikely that Saudi Arabia, the Middle East's dominant Sunni Muslim power, would take measures that would bolster its Shiite rival, Iran.

Iran recently ramped up crude exports after sanctions related to its nuclear program were lifted. The two countries also support opposing combatants in conflicts in Yemen and Syria.

"We are looking at the largest chasm between the Sunnis and the Shias within OPEC ever. Why would Saudi Arabia throw Iran a lifeline at this point?" he said.

Schork said he arrived at his conclusion by juxtaposing geopolitics with economics. Saudi Arabia and Iran are competing for available market share in Asia at a time when China is exporting deflation and Japan appears to be on the cusp of recession, he said.

In the more immediate term, Schork said he believes oil will test the $25 threshold once again as refineries enter their maintenance season and demand for crude falls.

Saudi Arabia can sustain the current policy for a long time because its break-even cost of producing the majority of its oil is likely below $10 a barrel, said Nansen Saleri, Quantum Reservoir Impact president and CEO.

However, he acknowledged that the Saudi economy, which is dependent on oil revenues, is suffering and the country has fallen into budgetary deficit.

"The pain threshold depends not only on the lifting cost but the total cost to the economy," he told "Squawk Box" on Wednesday.

Ultimately, the current low-price environment could last anywhere from six to 18 months, Saleri said. At some point, OPEC and non-OPEC producers must find a way to achieve a reasonable oil price.

http://www.cnbc.com/2016/02/24/schork-why-oil-wont-rebound-into-the-40s-this-year.html

The Caspian Pipeline Consortium (CPC), which brings oil from Kazakhstan to the Black Sea, plans to increase exports of CPC Blend oil by 20 percent year-on-year to 51.2 million tonnes in 2016, its head Nikolai Brunich said in an interview with Reuters.

The pipeline connects the giant Tengiz onshore field in Kazakhstan, and a number of other fields, to the sea terminal near Novorossiisk in Russia.

Despite weak global oil prices, CPC is still on track to increase the pipeline's capacity to 67 million tonnes in 2016, finishing its five-year expansion programme, according to Brunich.

The CEO hopes some of the new resources to help and fill the pipeline's expanded capacity will come from its largest supplier, Chevron-led Tengizchevroil, which is developing the Tengiz field.

Tengizchevroil plans to increase supplies via CPC by 4 million tonnes to 30 million tonnes in 2016, Brunich said.

He also believes new volumes will come this year from Kazakhstan's giant Kashagan project and from an offshore project by Russia's second-largest oil producer Lukoil.

CPC plans to receive this year 2.5 million tonnes of oil from Kashagan and 1 million tonnes from Lukoil's Filanovsky offshore oilfield in the Caspian Sea, the chief executive added.

Kazakh Deputy Energy Minister Magzum Mirzagaliyev said in December the restart of commercial production at Kashagan was not expected until the end of 2016 and by 2020 output will reach 13 million tonnes,

Brunich added he expected CPC to export 45 million tonnes of Kazakh oil and about 6 million tonnes of Russian oil in total in 2016. Russia owns 31 percent of CPC, while Kazakhstan holds a 21-percent stake and Chevron has a 15-percent stake.

http://www.reuters.com/article/oil-cpc-idUSL8N16339C

Private equity firm Warburg Pincus agreed to invest as much as $500 million in an oil and gas producer after commodities prices plummeted.

Warburg Pincus will give RimRock Oil & Gas a line of equity to help the startup company acquire and develop energy assets in North America, the companies said in a statement Wednesday. The money is coming from New York-based Warburg Pincus’s $12 billion private equity fundand its $4 billion energy fund.

While private equity firms have collected more than $20 billion for energy deals in the past two years, the money has largely remained on the sidelines, in part because oil producers have been unwilling to sell. That may quickly change, according to Deloitte LLP, which last week said more than one-third of listed producers worldwide are at high risk of bankruptcy, as their collective debt surged to about $150 billion and cash flows dwindled.

A global oil glut has caused a collapse in prices and led producers worldwide to reduce drilling, fire workers and cut dividend payments. West Texas Intermediate crude has slumped 70 percent since its mid-2014 peak and hit a 13-year low of $26.21 a barrel earlier this month.

“In light of the current commodity price environment, we believe there is a compelling opportunity to acquire and develop large-scale assets,” Jim Fraser, RimRock’s chief executive officer, said in the statement.

The sentiment was shared this week at the SuperReturn International conference in Berlin, where dealmakers from firms including Carlyle Group LP and Blackstone Group LP said they expect private equity firms to increase investments in oil and gas as producers become forced sellers.

Speaking at the conference Wednesday, Warburg Pincus Co-Chief Executive Officer Joe Landy said he expects oil producers and the banks that lent to them to take a hit as hedges continue to expire. Landy said oil and gas companies in which his firm has invested are “doing well.”

Among Warburg Pincus’s largest oil and gas holdings are Kosmos Energy Ltd., Antero Resources Corp. and Laredo Petroleum Inc., whose stocks have each fallen by more than half in the past two years, with Laredo slumping 84 percent.

http://www.bloomberg.com/news/articles/2016-02-24/warburg-pincus-to-invest-up-to-500-million-in-rimrock-oil-gas

Canada's Encana Corp cut its capital budget and production target for 2016 and said it would slash more jobs as the company struggles to cope with a steep fall in oil prices.

Encana lowered the upper end of its production target for this year to 360,000 barrels of oil equivalent per day (boepd) from 370,000 boepd, maintaining the lower end at 340,000 boepd.

The oil and natural gas producer also slashed its capital spending target to $900 million-$1 billion from $1.5 billion-$1.7 billion it forecast earlier.

Encana, which cut 200 jobs in July last year, said on Wednesday it would lay off 20 percent of its workforce this year.

The company reported a net loss of $612 million attributable to common shareholders for the fourth quarter ended Dec. 31. Encana had a profit of $198 million in the year-earlier quarter.

Excluding items, the company reported an operating profit of 13 cents per share, handily beating the analyst average estimate of 1 cent, according to Thomson Reuters I/B/E/S.

http://www.reuters.com/article/encana-results-idUSL3N16341O

U.S. natural gas producer Chesapeake Energy Corp more than halved its annual capital budget and said it would sell more assets this year.

The company's shares fell nearly 6.5 percent in premarket trading on Wednesday.

Chesapeake said it planned to spend $1.3 billion-$1.8 billion this year, down 57 percent from 2015 levels, and sell assets worth $500 million-$1 billion.

It said production could fall by as much as 5 percent this year due to the asset sales.

Chesapeake has struck deals to sell assets worth about $700 million this year so far, it said.

"We are also renegotiating gathering, transportation and processing contracts to better align with our current development plans and market conditions ..." Chief Executive Doug Lawler said in a statement.

Chesapeake reported a net loss of $2.23 billion, or $3.36 per share, attributable to shareholders for the fourth quarter ended Dec. 31. The company had a profit of $586 million, or 81 cents per share, a year earlier.

Excluding impairment charges of $2.83 billion and other items, Chesapeake reported a loss 16 cents per share, below the average analyst estimate of 17 cents, according to Thomson Reuters I/B/E/S.

http://www.reuters.com/article/chesapeake-enrgy-results-idUSL3N1634C4

Shaanxi Yanchang Petroleum (Group) Co, China's fourth-biggest oil producer by output, may cease production in some oilfields and stop drilling both old and new wells in some areas in response to the sharp plunge in crude oil prices, a media report said on Monday.

The Yan'an-based company faces huge pressure over soaring cost in terms of oil exploitation, personnel and operation. The cost for oil production at Yanchang stands at about $70 per barrel, against a national average of $40, according to sources quoted by Securities Daily.

In order to remain profitable, the State-run company also plans to cut capital spending by a total of 3.1 billion yuan ($480 million) this year and merge at least three oil drilling facilities, the report said.

Yanchang Petroleum lowered its oil output target to 12.2 million metric tons for this year, about 200,000 tons lower than a year earlier, according to a statement on the company's website.

The more than 50 percent slump in global crude oil prices since June has badly hit producer's earnings. Brent crude oil is currently below $30 a barrel, for the first time since May 2009.

Yanchang Petroleum is not the first firm to respond to the price dive by cutting spending or suspending production.

Shengli Oilfield, owned by China Petroleum & Chemical Corp, the nation's second-largest oil major, plans to shut down four oilfields in the country's eastern Shandong province to stay afloat.

The company, also known as Sinopec, said the four oilfields are the least profitable projects in the region with only a few tens of thousands tons of production, and the shutdown could save at least 200 million yuan.

At the same time, Daqing Oilfield, the largest oilfield explored by China's major oil and gas producer China National Petroleum Corp, reduced crude oil production in 2015 for the first time in seven years.

Though it is a painful process to make cuts or even suspend production, it is better to act early than leave it, experts.

"It is a normal practice when oil prices plunge. It is an adaption that oil companies have to make to meet market requirements," said Han Xiaoping, chief executive officer of online energy information portal China5E.com.

He said the cost for oil exploitation has been rising as some wells are getting old, but oil prices have been plummeting even faster, putting huge pressure on many large oil producers.

"Oil companies need to bring costs down in line with the current lower oil prices. Many foreign companies have also made plans to sell off part of their assets or even start drilling fewer wells," he said.

http://en.chinamining.com.cn/Companies/2016-02-24/1456276519d75366.html

Silver Run Acquisition Corp, a new U.S. investment vehicle, raised a greater-than-expected $450 million in an initial public offering on Tuesday aimed at funding the acquisition of energy companies, indicating investors see bargains amid the oil price rout.

The shares of many energy companies have been battered in the last 18 months as an oil supply glut has weighed on their prospects. Silver Run's IPO shows that some investors believe the sector's corporate valuations have reached bottom.

In the largest IPO so far this year in the United States, Silver Run said it had priced 45 million shares at $10 each, selling 5 million more shares than it originally planned.

Silver Run is a blank-check acquisition company sponsored by energy-focused private equity firm Riverstone Holdings LLC. Such so-called special-purpose acquisition companies (SPACs) fund the equity portion of their acquisitions through stock issuance.

Silver Run will look for companies that are "fundamentally sound" but underperforming due to current commodity prices, according to its IPO prospectus.

So-called secondary market investors are already placing bets that mergers and acquisitions will pick up in the oil patch by snapping up shares sold by publicly listed energy companies that could use the money to acquire assets at a discount. Silver Run's offering illustrates that SPACs can successfully make a similar pitch to IPO investors.

"(Secondary market) investors are participating in follow-on financings that make already strong companies stronger, enabling them to withstand even lower commodity prices or potentially even allowing them to play offense," said Americas equity capital markets head at Bank of Montreal Michael Cippoletti.

Silver Run's chief executive officer, Mark Papa, is an oil and gas veteran and Riverstone partner. He has worked for 45 years in the space, 15 of which were as CEO of EOG Resources Inc, once a division of Enron. Papa shifted EOG's focus from gas to oil, and is credited with transforming EOG into one of America's biggest oil companies.

Shares in Silver Run are expected to start trading on Wednesday and list on NASDAQ under the symbol "SRAQU".

http://www.reuters.com/article/us-silver-run-acqsn-ipo-idUSKCN0VW2MX

Asia's oil markets are being upended as India's and China's refiners overtake once-dominant buyers like Japan and challenge the United States as the world's biggest consumer.

The shifts are not only establishing new trade routes but are also challenging the way oil is priced in the region as the new players push for more cash cargoes and fewer long-term deals.

China and India's combined share of world oil consumption has tripled since 1990 to over 16 percent, nearing the U.S. share of roughly 20 percent, cementing their status as the main center of global demand growth.

"Asian oil markets are in a tremendous period of flux," said Owain Johnson, managingdirector of Dubai Mercantile Exchange (DME).

By 2040, China and India could double their share again to a third, analysts say.

One of Asia's rising traders is Indian Oil Corp, which operates 11 refineries with a combined capacity of 80.7 million tonnes a year (1.9 million barrels per day), a third of India's capacity and roughly the same size as Exxon's U.S. refining base.

"Spot crude (trading) gives more flexibility and more variety is available. Last year we raised spot purchases and for this year we are working out a strategy," said its head of finance A. K. Sharma.

The changes come at the expense of western majors, with Shell complaining in December that aggressive trading, conducted by Chinese companies, meant Asian crude prices didn't properly reflect the market.

"Chinese oil companies have become the new power houses in oil trading," said Oystein Berentsen, managing director of crude at Strong Petroleum in Singapore.

NEW PRIORITIES

Previously, Asia's largest oil buyers from Japan - which once accounted for about 10 percent of global demand - stuck with long-term contracts.

Now, as China and India take the lead, a growing share of trading is done on a spot basis as buyers prioritize cost and delivery flexibility over fixed shipment schedules.

Moreover, thanks to the hefty volumes, the new buyers are able to extract favourable prices. China and India's combined daily net crude imports exceed 10 million barrels, or some 3 million bpd more than top importer the United States.

The new buyers are also bringing new characteristics to the marketplace.

"Indians are more flexible than many of their Asian peers, buying up distressed or stranded cargoes when there's a profitable opportunity," said Ivan Szpakowski, head of Asia commodity research at Citigroup.

"India will become the biggest source of oil consumption growth. Its geography also changes trade flows. If you look at a map, the Middle East is much closer to India than to Japan or China and such shipments are effectively short-haul."

In China, state-owned oil giants have been joined by nearly 20 independent refiners which have been granted import licenses and exclusively buy spot supplies.

Their arrival is changing trade flows through their preference for cheaply-delivered Russian crudes which has helped Russia challenge the Middle East as China's biggest supplier.

NEW OIL PRICING?

Not all is smooth sailing. Richard Gorry, director of JBC Energy Asia, said the rise of these traders is causing "teething problems" as they make their first deals with highly regulated international companies.

In January, a crude cargo sold to an independent Chinese refiner by western merchants Vitol and Mercuria had to be resold after the firm failed to secure financing, while this month another private Chinese company walked away from a deal to buy $680 million of Russian oil, citing "changes in the market" as a reason.

http://www.reuters.com/article/asia-oil-markets-idUSKCN0VX07F

Petroleo Brasileiro SA, Brazil’s state-owned energy company, is scheduled to receive the first cargo of shale gas to be shipped from the U.S., according to a person familiar with the deal.

The shipment of liquefied natural gas was agreed to on Monday, said the person who asked not to be identified because the information isn’t public. Cheniere Energy Inc.began loading the first tanker at its Sabine Pass terminal in Louisiana, U.S. Coast Guard spokesman Dustin Williams said in an e-mail Tuesday.

“The biggest buyer of LNG outside of the winter is Brazil first and Argentina second in the Atlantic Basin," said Ted Michael, an analyst for energy data provider Genscape Inc.“They buy LNG for gas-powered, air-conditioned power."

Fuel Glut

America’s first LNG export will hit the water just as a glut of the fuel emerges in the global market, weighing on prices. Other gas-export projects are expected to come under pressure to secure financing and long-term contracts amid the global commodity rout and shifts in demand overseas, Daniel Yergin, vice chairman of the energy consulting group IHS Inc., said in an interview Feb. 17.

Demand is forecast to be higher in South America during the spring, in part due to a drought that has increased Brazil’s dependence on the power-plant fuel. Brazil has increased LNG imports in the past few years after an agreement to buy gas via a pipeline from Bolivia reached its limits.

Loading the Asia Vision, the LNG tanker that moored at the Sabine Pass on Feb. 21, may take a few days and the timing of its departure is unclear, Williams said. Genscape, which has cameras pointed at the terminal, said the vessel began unloading ballast water shortly after it arrived and has continued to do so, which is “consistent with taking on more weight from LNG loading onto the ship,” analyst Jason Lord said in an e-mail Tuesday. He estimated it may take closer to 36 hours to load the Asia Vision.

http://www.bloomberg.com/news/articles/2016-02-23/petrobras-said-to-buy-cheniere-s-first-u-s-shale-gas-export?cmpid=yhoo.headline

Stone Energy (NYSE: SGY) reported Q4 EPS of $0.04, $0.04 worse than the analyst estimate of $0.08.

Reserves

Our estimated proved reserves as of December 31, 2015 were 57 MMBoe (million barrels of oil equivalent) or 342 Bcfe (billion cubic feet of natural gas equivalent), compared to 153 MMBoe (915 Bcfe) at year-end 2014. The decrease in estimated proved reserves is primarily attributable to the downward revision of 95 MMBoe (570 Bcfe) to contingent resources due to depressed commodity prices. Substantially all of Stone's proved reserves in Appalachia were reclassified to contingent resources during 2015. From drilling additions, extensions, well performance, and the acquisition of Appalachia working interests, Stone replaced approximately 104% of 2015 production.

The year-end 2015 estimated proved reserves were 53% oil, 11% natural gas liquids (NGLs) and 36% gas on an equivalent basis. The changes from year-end 2014 estimated proved reserves to year-end 2015 estimated proved reserves included production of approximately 14 MMBoe (85 Bcfe), divestitures of 1 MMBoe (6 Bcfe), drilling additions/extensions of 1 MMBoe (7 Bcfe), acquisition of working interest in Appalachia of 6 MMBoe (34 Bcfe), positive performance revisions of 8 MMBoe (47 Bcfe) and net downward price revisions of 95 MMBoe or 570 Bcfe.

The standardized measure of discounted future net cash flows from our estimated proved reserves at December 31, 2015, using a 10% discount rate and 12-month average prices (after differentials) of $51.16 per barrel of oil, $16.40 per barrel of NGLs and $2.19 per Mcf of gas, was approximately $604 million. Estimated future income taxes had no effect on the standardized measure as of December 31, 2015. If current pricing was used to determine the estimated proved reserves or the standardized measure at December 31, 2015, the reserve volumes and values would be reduced.

The year-end 2015 estimated proved reserves included proved developed (PD) reserves of 42 MMBoe or 249 Bcfe (52% oil, 12% NGLs, 36% gas) and proved undeveloped (PUD) reserves of 15 MMBoe or 93 Bcfe (55% oil, 11% NGLs, 34% gas). In addition, there were 23 MMBoe or 139 Bcfe of estimated probable reserves and 59 MMBoe or 356 Bcfe of estimated possible reserves at year-end 2015.

All of Stone's estimated proved, probable and possible reserves and contingent resources were independently engineered by Netherland Sewell & Associates.

http://www.streetinsider.com/Earnings/Stone+Energy+(SGY)+Misses+Q4+EPS+by+4c/11347087.html

It appears oil traders are disappointed with Al-Naimi's comments. Suggesting hopefully (for some) that the 'freeze' is the start of a process, al-Naimi then dropped the tape-bomb:

*SAUDI ARABIA WON'T CUT OIL PRODUCTION: NAIMI
*HIGH-COST PRODUCERS MUST LOWER COSTS OR LIQUIDATE: NAIMI

He then added that "not all the countries will freeze; The ones that count will freeze."  "We met with non-OPEC, we asked them what are you going to do, they said nothing

http://www.zerohedge.com/news/2016-02-23/oil-erases-yesterdays-gains-al-naimi-says-saudi-arabia-will-not-cut-production-live-

Oil futures lost more ground on Tuesday after Saudi Arabia's Oil Minister Ali al-Naimi said he has no concerns about oil demand and that he welcomes additional supplies, including shale oil. He emphasized in his speech at IHS CERAWeek that "we have not delcared war on shale" or on production from any country or company. "Our purpose is not market share." Al-Naimi said oil is in a "painful downturn" but the market will be balanced and demand will pick up.

NatGas taken from Alberta storage since Nov 1 is now a miserly 31 bcf, the smallest cumulative storage withdrawal in past 25 years

@OilandGasInvest

Despite OPEC's El-Badri proclaiming that Iran and iraq "didn't refuse to join the production freeze," oil prices are tumbling this morning on comments from Iran's oil minister that OPEC's call for a production freeze is "ridiculous."

Proposal by Saudi Arabia, Russia, Venezuela, Qatar for oil producers to freeze output puts “unrealistic demands” on Iran, Oil Minister Bijan Namdar Zanganeh says, according to ministry’s news agency Shana.

*IRAN CALLS SAUDI-RUSSIAN OUTPUT FREEZE PLAN `RIDICULOUS': SHANA

http://www.zerohedge.com/news/2016-02-23/oil-drops-after-iran-slams-opec-production-cut-ridiculous

Japan will likely refrain from loading oil at Iranian ports in March because of the impending expiry at the end of next month of special shipping insurance cover provided by the government, industry and government officials said.

The potential restriction from one of Tehran's biggest oil customers highlights Iran's difficulties in boosting exports after U.S. sanctions were lifted in January. The problem stems from confusion about whether U.S. companies can offer insurance coverage for tankers with Iranian crude.

The U.S. removed the sanctions after confirming a deal on Iran's disputed nuclear programme, including prohibitions on non-American companies selling insurance to and trading with Iranian entities.

But the Treasury Department left in place other sanctions limiting the amount of reinsurance U.S. companies can provide for Iranian ships, a crucial element in providing tanker cover.

The insurance ban was the most effective way of limiting Iranian oil exports, which were more than 3 million barrels per day (bpd) in 2011, but fell to a little more than 1 million bpd after the sanctions were imposed in 2012.

Japan has kept the oil trade with Iran going through a special government insurance programme that gives about $8 billion in coverage and the government plans to renew it with a parliamentary vote, a government source said.

But, given the lack of a timetable on the vote, shippers are erring on the side of caution and will likely hold back from any loadings next month, the government source and industry sources, who requested anonymity, said.

International insurers are trying to put together limited coverage to complement the lack of U.S. cover, but it is uncertain whether the Washington will approve the plans, officials at Japan's main insurer, the Japan P&I Club, said.

European nations have resumed loading Iranian oil despite the international P&I club only providing coverage for about 85 percent of the roughly $8 billion per ship normal liability coverage, but Japanese shippers are still holding back, said the officials.

Japan is set to load 202,000 barrels per day (bpd) of Iranian crude in February, down 8 percent from a nine-month high in January, said an industry source familiar with the matter.

Japan's Iranian crude imports last year halved from 2011 levels to about 156,000 bpd amid the sanctions.

http://www.reuters.com/article/iran-oil-japan-idUSL3N1621YQ

Azeri state oil firm Socar's trading division is looking to reactivate deals with Iran, as well as expanding into new markets ranging from North American crude to natural gas in Europe, its chief executive told Reuters.

Neighbours Azerbaijan and Iran have been strengthening ties since the removal of sanctions against Tehran in January and on Tuesday Iran's national oil company NIOC and Socar signed a memorandum of understanding as part of a visit by Azeri President Ilham Aliyev to the Islamic Republic.

"We have been actively trading with NIOC in the Caspian Sea region, until international sanctions forced us to discontinue such deliveries. There is a great potential to explore," Arzu Azimov, the chief executive of Socar Trading, said.

Other possibilities include trading refined products with Iran in the Gulf, where Socar has storage facilities in the United Arab Emirates port of Fujairah. One option was to supply Iran with gasoline and to buy naphtha and liquefied petroleum gas (LPG), Azimov said.

Geneva-based Socar Trading was set up in 2007 as the trading arm of Socar to market Azeri volumes. It expanded into crude processing and paper trading for hedging purposes before gradually trading third part crude and products.

Azimov said Socar Trading, which currently employs less than 200 people globally sees its role as somewhat different from the trading arms of many national oil companies.

"Where the market is oriented towards direct deals between producers and consumers, there is no space for trading houses. We need to be customer oriented. I see us as a services provider," Azimov told Reuters.

He said about 90 percent of its profit was from outside trading of its parent company's oil or products and it was expanding in new markets beyond oil, such as LNG.

"We decided that buying and selling LNG wasn't terribly attractive. So we started looking at other options. We looked at Malta, an interesting case as it is not connected to an EU gas grid and has been burning fuel oil for heating needs," he said.

Socar Trading won a tender with a consortium including Germany's Siemens to supply LNG and build a re-gasification facility for the Mediterranean island, with supplies due to begin next year.

Socar Trading plans to open an office in Houston to trade and arbitrage oil and products in and out of the United States. It already has a business unit in Calgary, where it is actively exploring trading opportunities between the U.S. and Canada.

http://www.reuters.com/article/azerbaijan-socar-trading-idUSL8N1622J8

Carrizo Oil & Gas, Inc.  today announced the Company's financial results for the fourth quarter of 2015 and provided an operational update, which includes the following highlights:

- Record Oil Production of 24,942 Bbls/d, 13% above the fourth quarter of 2014
- Record Total Production of 40,159 Boe/d, 7% above the fourth quarter of 2014
- Loss From Continuing Operations of $380.7 million, or ($6.73) per diluted share, and Adjusted Net Income (as defined below) of $18.5 million, or $0.32 per diluted share
- Adjusted EBITDA (as defined below) of $112.1 million
- Delivered 246% reserve replacement from all sources with a drill-bit F&D cost of $15.40 per Boe
- Announcing 2016 drilling and completion capital expenditure plan of $270-$290 million
- Announcing 2016 crude oil production growth target of 8%

Carrizo reported a fourth quarter of 2015 loss from continuing operations of $380.7 million, or $6.73 per basic and diluted share compared to income from continuing operations of $129.5 million, or $2.84 and $2.79 per basic and diluted share, respectively, in the fourth quarter of 2014. The loss from continuing operations for the fourth quarter of 2015 includes certain items typically excluded from published estimates by the investment community, including the full cost ceiling test impairment recognized this quarter. Adjusted net income, which excludes the impact of these items as described in the statements of operations included below, for the fourth quarter of 2015 was $18.5 million, or $0.33 and $0.32 per basic and diluted share, respectively, compared to $14.8 million, or $0.32 per basic and diluted share in the fourth quarter of 2014.

For the fourth quarter of 2015, adjusted earnings before interest, income taxes, depreciation, depletion, and amortization, as described in the statements of operations included below ('Adjusted EBITDA'), was $112.1 million, a decrease of 13% from the prior year quarter as the impact of lower commodity prices more than offset the impact of higher production volumes.

More information and prices

Production volumes during the fourth quarter of 2015 were 3,695 MBoe, or 40,159 Boe/d, an increase of 7% versus the fourth quarter of 2014. The year-over-year production growth was driven by strong results from the Company's Eagle Ford assets. Oil production during the fourth quarter of 2015 averaged 24,942 Bbls/d, an increase of 13% versus the fourth quarter of 2014 and 6% versus the prior quarter; natural gas and NGL production averaged 67,110 Mcf/d and 4,032 Bbls/d, respectively, during the fourth quarter of 2015. Fourth quarter of 2015 production exceeded the high end of Company guidance due primarily to strong performance from the Company's Eagle Ford assets.

Drilling and completion capital expenditures for the fourth quarter of 2015 were $104.5 million. More than 75% of the fourth quarter drilling and completion spending was in the Eagle Ford. Land and seismic expenditures during the quarter were $9.5 million.

Given the decline in commodity prices, Carrizo is reducing its planned capital spending in 2016 vs. 2015. Carrizo's initial 2016 drilling and completion plan is $270-$290 million, a decrease of nearly 45% from the 2015 level. This level of spending should allow the Company to run one to two rigs in the Eagle Ford during the year as well as continue to test its acreage in the Delaware Basin. The Company's initial land and seismic capital expenditure plan is $15 million.

Based on this level of activity, Carrizo is providing initial 2016 oil production guidance of 24,700-25,300 Bbls/d. Using the midpoint of this range, the Company's 2016 oil production growth guidance is 8%. For natural gas and NGLs, Carrizo is providing initial 2016 guidance of 45-60 MMcf/d and 3,700-4,000 Bbls/d, respectively. For the first quarter of 2016, Carrizo expects oil production to be 24,800-25,200 Bbls/d, and natural gas and NGL production to be 60-64 MMcf/d and 3,800-4,000 Bbls/d, respectively. Additionally, Carrizo currently expects crude oil production in the fourth quarter of 2016 to exceed crude oil production in the fourth quarter of 2015. A summary of Carrizo's production, commodity price realization, and cost guidance is provided in the attached tables.

http://www.oilvoice.com/n/Carizzo-Oil-Gas-announces-2015-fourth-quarter-and-yearend-results-provides-2016-guidance/067ca47e57bd.aspx

Tokyo Electric Power (Tepco) revealed its LNG imports in January stood at 1.8 million mt, 21 percent down from 2.28 million mt during the same month 2015.

Tepco’s consumption of LNG also dropped to 1.99 million mt in December 2015, 15.1 percent lower compared to January 2015, fuel data released by the Japanese utility reveals.

In the period spanning from April to January, Tepco imported 18.66 million mt and consumed 17.91 million mt of liquefied natural gas.

Tepco is Japan’s first importer of LNG and it imports the fuel from projects located in Brunei, the United Arab Emirates, Malaysia, Indonesia, Australia, Qatar, Darwin, Oman, Russia and Papua New Guinea.

http://www.lngworldnews.com/tepcos-january-lng-imports-slide/

Oil Search chief executive Peter Botten says the time is ripe for much closer ties between the company's two liquefied natural gas projects in Papua New Guinea, to help counter the collapse in oil prices that has clouded the prospects for even the most competitive of petroleum ventures.

"It is a high priority in 2016 to discover how these things can be brought together," Mr Botten said after announcing Oil Search's swing to a $US39.4 million ($54.8 million) loss for the full year.

"The focus of every board and management is on driving every single dollar further and getting the best possible value out of that investment. There could not be a better environment to discuss co-operation."

The drop in oil prices has cut revenue for the Papua New Guinea LNG project. 

Oil Search, which in 2015 rebuffed an $11.6 billion takeover approach from Woodside Petroleum, is ExxonMobil's biggest partner in the successful PNG LNG venture, which began production in 2014 and is working towards adding a third production unit. It also has a stake in the Papua LNG venture with French oil major Total and US-listed InterOil, which is seeking to develop a separate project using gas from the large Elk-Antelope field using the same processing site near Port Moresby.

Mr Botten said the base case for the projects still involved separate production units, with the expansion of PNG LNG running ahead of plans for an initial LNG train at Papua LNG.

At Papua LNG, the results of an independent assessment to determine how much gas Elk-Antelope holds is expected by mid-year, driving whether the project could involve one or two LNG trains.

LNG projects still viable

The two LNG projects, widely seen as the most competitive in Asia, were still viable on probable oil and LNG price scenarios, Mr Botten said, while admitting that any large project would need prices higher than today's of just more than $US30 to proceed.

Still, oil prices should have stabilised and be on a path to recovery by the time of the final go-ahead decisions on both projects, which were due in only "maybe two years' time", he said.

Oil Search's full-year loss was forced by a $US399.3 million write-down on the Taza exploration venture in Kurdistan, which the company is looking to sell.

Oil Search was also expecting to be active as an acquirer, and was eyeing potential assets in PNG, Mr Botten said.

"I do see a range of potential opportunities in Papua New Guinea that would support the strategy we have to commercialise our gas resources," he said.

The interim loss compared with a profit of $US353.2 million a year earlier. Revenue fell 2 per cent to $1.58 billion.

Core net profit for 2015 fell 25 per cent to $US359.9 million, about in line with consensus.

Oil Search declared a final dividend of US4¢ a share, taking the full-year payout to US10¢, down from US14¢ for 2014.

Cost-cutting is still in full swing at the company, with Mr Botten targeting a further 25 per cent reduction in production costs in 2016, and capex to be slashed 34 per cent.

Read more: http://www.smh.com.au/business/energy/oil-search-forced-into-loss-by-writedowns-20160222-gn0ku6.html#ixzz40yeTYVVS
Follow us: @smh on Twitter | sydneymorningherald on Facebook

China's emergence as a major oil product exporter is depressing oil refining margins across Asia as favorable domestic fuel policies encourage Chinese refiners to keep output high and flood regional markets with surplus supplies.

The surge in Chinese shipments has been felt the most in the diesel market, where benchmark Asian margins recently slumped to 6-year lows following an almost 80 percent jump in Chinese exports in 2015.

The world's No.2 diesel producer had until last year been only a modest exporter of the fuel, as the country's large mining, power generation and trucking industries used up most of its diesel output.

But as China's industrial engine slowed, refinery run rates remained high to meet still strong demand for gasoline and jet fuel, used for transport. That led to a surplus of diesel that was steered on to regional markets with increased aggression over the course of 2015.

Average monthly exports over the second half of 2015 were 865,000 tonnes, compared to 329,000 tonnes a month over the first half.

"As independent refineries in China have increased access to crude, this positively affects their run rates. In turn every additional barrel in the already oversupplied middle-distillates market has a negative effect on the gasoil margins," said David Wech, managing director of research institute JBC Energy.

Additional export quotas for independent refineries along with export-linked incentives for refineries owned by state-owned oil giant Sinopec Corp are expected to lead to higher shipments in 2016. January exports eased back from December levels, but were more than 10 times higher than the same month in 2015.

China's net surplus of diesel could more than double to 220,000 barrels per day or about 10.8 million tonnes in 2018 from 100,000 bpd in 2015, Wech said.

"The sizable diesel supply glut created by an upsurge in Chinese exports of diesel ...(will) remain intact, leading diesel prices in Asia to underperform diesel prices in Europe and North America over 2016 to 2020," said BMI Research's Asia oil analyst Peter Lee.

While China's increased exports have slashed Asian diesel margins - from roughly $16 a barrel a year ago to around $10 now - the impact has been partly offset by tumbling oil prices, which have kept other refiners profitable.

Chinese refiners have also been protected by a domestic floor price that is above international rates and provides a buffer for competitively priced exports.

On a monthly basis, China has already overtaken Japan and Taiwan to become Asia's fourth-largest diesel exporter after South Korea, Singapore and India.

China accounted for 12 percent of Asian diesel exports in the month of December, 2015, up from just four percent nine months earlier, according to trade data and a Reuters analysis of ship loadings in the region.

New refineries in China are also able to meet more stringent specifications required by developed countries such as Australia, where the closure of aging refineries has boosted import demand.

"I think the immediate attraction for them is Australia and maybe to some extent Africa, but I'm sure they will want to expand their reach to Europe and the United States," said a source with a Japanese refiner.

http://www.reuters.com/article/us-china-diesel-exports-idUSKCN0VV2IQ

The world's biggest oil producers may consider "other steps" to eliminate a persistent global oversupply if a recent deal to freeze current output holds firm for several months, the top official of the Organization of the Petroleum Exporting Countries said on Monday.

OPEC Secretary-General Abdullah al-Badri reiterated the group's readiness to work with non-OPEC producers to tackle a supply glut that has knocked prices to their lowest in over a decade. He told the IHS CERAWeek conference in Houston that the tentative pact to freeze output reached last week between Saudi Arabia, Russia, Venezuela and Qatar was just a start.

Al-Badri admitted the oil cartel had not expected prices to fall so sharply since the group decided in late 2014 not to cut output in the face of rising global supplies, fueled in large part by the fast growth of the U.S. shale production.

"This cycle is very nasty," Badri said.

He said OPEC had also held talks with other key producers including Brazil, China, Oman and Mexico on a possible freeze.

Other steps could include a production cut.

"Let us freeze production... If this is successful we can take other steps in the future," Badri said. Parties must first manage to cap output levels for three to four months, he added.

He nevertheless cautioned that when oil prices recover from their current levels in the mid-$30 per barrel to around $60 per barrel, shale producers would quickly start drilling again, capping any gains.

Global production exceeded demand by as much as 2 million barrels per day last year. A gradual decline in output due to lower investment is expected to balance the market in early 2017, according to the International Energy Agency.

However, a huge build in global oil inventories, which Badri said has reached 350 million barrels, means it will take longer for prices to recover.

He underlined that understanding between OPEC and non-OPEC producers is increasingly necessary to balance the market.

Addressing a room filled with hundreds of global oil executives, Badri said he was willing to speak with U.S. officials about the collapse in oil prices.

The rout in prices of more than 70 percent in 20 months, is not the same as oil's previous boom-bust cycles, he said.

"I don't know how we are going to live together," Badri said of the once booming shale oil sector. "If prices will go up in 2017 or 2018, the price rally will be capped by U.S. shale oil. That's what is different this time."

Any deal on a production freeze would be tough to implement. Iran, which has pledged to increase output sharply since sanctions were lifted last month, has yet to formally sign on to the agreement, leaving its implementation uncertain.

http://www.reuters.com/article/us-ceraweek-opec-idUSKCN0VV2IC

Drilling activity has crashed, but efficiencies and American ingenuity have helped make each well far more productive.

The number of oil rigs fell by 26 last week to 413, Baker Hughes (BHI) reported Friday. That’s down 19% over the last four weeks and 59.5% vs. a year earlier.

But U.S. oil output, though off peak levels, has held up remarkably well. That’s in large part because Continental Resources, Concho Resources and other shale producers are becoming, well, more productive with every well. They focused on the best wells, kept the best crews, while employing new technical advances and practices. They’ve also been able to squeeze suppliers and services firms such as Baker Hughes, Schlumberger  and Halliburton.

• Bakken Shale new wells should produce 737 barrels per day in March, up from 558 bpd in March 2015. That’s a 32% increase — 88.5% vs. March 2014.

• Eagle Ford new wells are expected to generate 812 barrels per day in March, up from 665 bpd a year earlier. That’s a 22% jump.

• Niobrara new wells should produce 741 barrels per day, up 39% from 533 bpd in March 2015.

• Permian Basin new wells should produce a 423 barrels per day, a 49% spike from 284 bpd a year earlier.

• Utica new wells should generate 309 barrels per day, a whopping 83% increase from 168 bpd in March 2015.

Continental Resources, Concho Resources and other shale firms have been able to concentrate efforts, slashing capital spending and operating costs without a big blow to production. But with oil down to $30 a barrel or lower, these companies are under heavy  strain. Continental and Concho earnings reports are due this week, with the former expected to post a loss and the latter a 96% EPS dive.

As for suppliers such as Halliburton, Schlumberger and Baker Hughes, they’ve cut tens of thousands of jobs.  But those oil services giants should emerge stronger after the oil bust, D.A. Davidson said in research reports last week.

http://www.investors.com/news/oil-rigs-dive-to-2009-levels-but-well-productivity-soars/?ven=YahooCP&src=AURLLED&ven=yahoo

Global surplus refining capacity is expected to rise by more 1 million b/d to 5.3 million b/d in 2021 creating "significant pressure" on refining margins in the medium term, the International Energy Agency said Monday.

In addition to nearly 8 million b/d of new global refining capacity due to come on stream over the next five years, growing volumes of non-refining fuels mean the gap between capacity expansions and demand will rise to about 2 million b/d, according to the IEA's latest medium-term report.

Global crude distillation capacity is expected to rise by 7.7 million b/d from 2016 to 105 million b/d in 2021, the IEA said.

Regionally, nearly two-thirds of global spare capacity will be found in non-OECD countries, where many refineries are under-utilized for various reasons, the IEA said.

It cautioned, however, that the oil price downturn has raised the likelihood of delays for many new refining projects as oil companies seek to conserve their dwindling cash flows.

Annual capacity additions are estimated to average 1.3 million b/d through 2021, despite some 1.7 million b/d of projects deferred beyond 2021, the IEA said.

The IEA said it sees low capacity additions this year -- about half of the expected annual demand growth -- potentially tightening the oil product market. But a massive overhang of oil product stocks means a resulting margin boost "may not materialise".

The IEA estimates that almost one-sixth of global oil demand will be met by fuels by-passing the refining sector such as biofuels and NGL's in 2021, which will exacerbate the surplus capacity issue.

Global biofuels production is estimated to rise to 2.7 million b/d in 2021, up from 2.3 million b/d in 2015.

http://www.platts.com/latest-news/oil/london/global-excess-refining-capacity-to-grow-11-million-26375268

The European Union suspended the deadline for its review of Halliburton Co.’s acquisition of Baker Hughes Inc.as regulators said the companies failed to supply “important information.”

The EU regulator “stopped the clock in its in-depth investigation into the Baker Hughes -- Halliburton deal,” EU spokesman Ricardo Cardoso said in an e-mailed response to questions. The move could mean the EU delays its decision on the merger of the two oil services rivals past the existing deadline of June 23.

“This is a standard procedure on merger investigations which is activated if the notifying parties do not provide an important piece of information,” he said. “The clock is then stopped until such missing information is supplied the deadline for the decision date will be adjusted accordingly.”

The EU review of the deal was previously held up last year by four months after regulators rejected the companies’ initial filing as incomplete.

Halliburton agreed to buy Baker Hughes in November 2014 in a cash-and-stock deal that at the time was valued at about $35 billion. The transaction was scheduled to close last year, but has been delayed as the companies seek to resolve antitrust concerns in the U.S. and Europe.

Emily Mir, a spokeswoman for Halliburton, did not immediately reply to a request for comment outside Houston working hours.

Halliburton has been adding yet more assets to the list of businesses it plans to sell to gain antitrust approval. The company plans to divest Baker’s offshore drilling-and-completions fluids division and the bulk of Baker’s completion systems, people familiar with the matter said earlier this month.

The EU merger authority opened an in-depth probe into the deal on Jan. 12, citing concerns that combining the the second- and third-largest suppliers to oil exploration companies may impede competition and increase prices.

http://www.bloomberg.com/news/articles/2016-02-22/halliburton-deal-deadline-suspended-as-eu-seeks-more-data

Oil markets will begin to rebalance in 2017 thanks to falling U.S. production but that decline will prove short-lived as efficiency gains will push U.S. output to new records by the beginning of the next decade, the International Energy Agency said on Monday.

"Only in 2017 will we finally see oil supply and demand aligned but the enormous stocksbeing accumulated will act as a dampener on the pace of recovery in oil prices when the market, having balanced, then starts to draw down those stocks," the IEA said in its medium-term outlook.

"Today's oil market conditions do not suggest that prices can recover sharply in the immediate future," it added.

Over the course of 2015 to 2021, U.S. output is expected to reach a record high of 14.2 million barrels per day (bpd), after dipping initially this year and next, the IEA said in its report.

Production of U.S. shale oil, known as light, tight oil (LTO), is expected to drop by 600,000 bpd this year, and a further 200,000 bpd next year before gradually recovering.

"Anybody who believes that we have seen the last of rising LTO production in the United States should think again; by the end of our forecast in 2021, total U.S. liquids production will have increased by a net 1.3 million bpd compared to 2015," the IEA said.

Overall, global oil supply is expected to rise by 4.1 million bpd between 2015 and 2021, compared with growth of 11 million bpd between 2009 and 2015, the IEA said.

The report forecast OPEC crude oil production capacity would rise by 800,000 bpd by 2021 as lower oil prices force the re-consideration of development projects in the early period of the forecast.

"Iran, now free of nuclear sanctions, emerges as the biggest source of growth within OPEC over the six-year forecast period. The higher capacity will not, however, allow Iran to reclaim its rank as OPEC's second-biggest crude oil producer after Saudi Arabia. That position is maintained by Iraq through 2021 despite a marked slowdown in its capacity building," the IEA said.

http://www.reuters.com/article/iea-outlook-idUSL8N1611YW

The Panama Canal is set to open the Third Set of Locks expansion project in the second quarter of 2016, which will allow Suezmax tankers, carrying cargoes of up to 130,000 mt or 1 million barrels of petroleum liquids, to transit the waterway, a source said Friday. The current cargo limit is 55,000-60,000 mt.

Grupo Unidos por el Canal (GUPC), the consortium responsible for the design and construction of the expansion, successfully completed testing of the reinforcements in sill number three of the expanded Pacific locks earlier this week and less than 4% of the overall project work remains to be completed, according to the canal operator, the Panama Canal Authority. The canal expansion is expected to be inaugurated later this year, it said.

Repairs to a large crack at the third set of locks, which first appeared in August 2015 at the concrete sill between the lower and middle chamber of the Cocoli locks, have been fixed, it said. "We expect to be operational in the second quarter of 2016," a PCA source told Platts Friday.

Once the expansion is completed, the draft for vessels transiting the canal will increase from the current 39.05 feet in the old locks to 50 feet in the new locks. While the PCA does not limit deadweight tonnage, the expanded locks can accommodate larger size vessels, as maximum beam increases from 106 feet to 140 feet and overall length (LOA) from 965 feet to 1,200 feet, according to the PCA source.

http://www.platts.com/latest-news/shipping/houston/panama-canal-expansion-to-transit-suezmaxes-from-21967598

Platts JKM for LNG cargoes delivered in April, the new front month, ended the Asian trading week at $4.65/MMBtu Friday, down 5 cents/MMBtu from Tuesday when the assessment for April JKM started.

Platts JKM for March cargoes finished its assessment period Monday at $5.30/MMBtu.

Offers for April cargoes were heard to be in the high $4s/MMBtu by the end of the week while bids were heard to be in the low to mid-$4s/MMBtu.

Expectations that new supply will emerge with new projects such as Australia's Gorgon coming online also weighed on the market.

Throughout the week trade was thin and market participants waited for the results of buy tenders issued by Thailand's PTT and India's Gail.

Thailand's PTT awarded its tender to buy a cargo delivery March 20-28 at slightly below $5/MMBtu to Qatar Gas, according to market sources.

Another tender which drew attention was India's Gail tender, which was awarded at $4.70/MMBtu for one April delivery cargo and at low $5s/MMBtu for two March cargoes.

Another Indian buyer IOC was reportedly awarded an earlier tender that closed on February 2, though details remained scarce.

Meanwhile, Pakistan State Oil cancel led its LNG buy tender for five DES cargoes while Argentina was expected to issue a tender next month for cargoes to meet its summer demand.

In Russia, Sakhalin Energy again postponed the deadline of a sell tender offering one to two cargoes a month over April 2016-March 2017 to March 1. The tender was issued in the week of January 24, with the initial deadline of February 2 postponed to February 24 after a force majeure was declared at the plant in late January.

Sakhalin Energy also moved up the completion data for its repair work to March 4 from the earlier deadline of March 11, sources said.

In other production news, 4.45 million mt/year Peru LNG export plant has resumed normal operations after a month-long unplanned shutdown, a spokesman with US-based Hunt Oil, the plant's operator, said late Wednesday.

And the 3.7 million mt/year Equatorial Guinea LNG plant in West Africa also restarted normal operations after one month of scheduled maintenance, a source close to the facility said Tuesday.

http://www.platts.com/latest-news/natural-gas/tokyo/asia-spot-lng-april-platts-jkm-ends-week-at-465mmbtu-26373907

The number of rigs drilling for oil in the U.S. dropped by 26 this week, leaving just 413 rigs still seeking crude, according to Baker Hughes data.

Including gas rigs, the overall rig count of 514 rigs is at its lowest point since the last century, specifically 1999.

The total count is rapidly approaching the 1999 low of 488 rigs, which was the lowest point in Baker Hughes’ recorded history. Another drop of 26 rigs would tie the all-time record low.

Analysts expect the rig count to continue falling through much of the first half of the year. The U.S. benchmark for oil continues to hover at about $30 a barrel.

In the first two months of 2016 alone, drillers have mothballed 123 oil rigs. The natural gas rig count dropped by just one this week down to 101 rigs, which already is at a historic low.

Texas is still home to 46 percent of the nation’s operating rigs, but the biggest losses this week came from the Lone Star State. Seven rigs went dark in the Permian Basin and the Eagle Ford shale lost another four rigs. The Permian and Eagle Ford, in that order, are still the most active plays in the country.

The oil rig count is now down nearly 75 percent from its peak of 1,609 in October 2014 before oil prices began plummeting.

http://fuelfix.com/blog/2016/02/19/oil-rig-count-plummets-yet-again/

Feb 22 When Sheikh Ali Khalifa al-Sabah of Kuwait thinks about today's plunging oil prices, his mind drifts back to the mid-1980s, when he was forced to sell some of his country's crude for as little as $5 a barrel.

As Kuwait's oil minister at the time, Sheikh Ali had to sell a cargo or two at that price just to keep up cash flow to a country that depended upon oil revenues. "It wasn't because I wanted to; it was because it was the market price," he recalls.

"We really had no alternative."

For oil industry players active during the 1980s bust, the current drop in prices carries echoes of those desperate days. Interviews with some of those involved in that period reveal that while there is little consensus on how long prices will stay depressed, experience suggests the current market glut will not evaporate soon.

Representatives from all aspects of the energy industry will be mulling current low oil prices and the supply glut this week during the IHS CERAWeek gathering in Houston.

Kuwait's struggles in the 1980s are instructive for anyone wondering whether producing countries can tinker their way out of trouble now. In the face of weak prices in the early years of the decade the OPEC production group introduced output cuts in an attempt to mop up oversupply. Kuwait slashed production from nearly 2 million barrels per day to about 600,000 bpd. The top producer Saudi Arabia made even costlier cuts.

Three factors dashed the plan: fellow OPEC members cheated on their own cuts; global thirst for oil had dried up after price spikes in the 1970s pushed consumers to buy efficient cars; and new supplies, particularly from non-OPEC Mexico, Norway, and Alaska threatened to squash gains from any cuts.

By late 1986, Saudi Arabia and other OPEC members opened the taps again to regain market share, and prices did not recover for 20 years.

The memory leaves Sheikh Ali, now 71, feeling grim about a price recovery this time.

"Tomorrow if the price of oil goes down to $20 I would not be surprised," he said. "You don't take excess oil away very quickly. It was true in the 1980s, now it's even worse."

Adrian Lajous was head of crude exports trading for Pemex, Mexico's state oil company in the mid-1980s. He says major oil producers are powerless to tackle the current oversupply by making production cuts, despite an agreement this month between Saudi Arabia and Russia to freeze supply.

Today's bust is driven by uncertainty about demand - mostly China's - and by the threat of a resilient non-OPEC supply, mostly from U.S. shale oil.

http://www.reuters.com/article/ceraweek-glut-idUSL2N15X2RA

Within weeks, two low-profile legal disputes may determine whether an unprecedented wave of bankruptcies expected to hit U.S. oil and gas producers this year will imperil the $500 billion pipeline sector as well.

In the two court fights, U.S. energy producers are trying to use Chapter 11 bankruptcy protection to shed long-term contracts with the pipeline operators that gather and process shale gas before it is delivered to consumer markets.

The attempts to shed the contracts by Sabine Oil & Gas (SOGCQ.PK) and Quicksilver Resources (KWKAQ.PK) are viewed by executives and lawyers as a litmus test for deals worth billions of dollars annually for the so-called midstream sector.

Pipeline operators have argued the contracts are secure, but restructuring experts say that if the two producers manage to tear up or renegotiate their deals, others will follow. That could add a new element of risk for already hard-hit investors in midstream companies, which have plowed up to $30 billion a year into infrastructure to serve the U.S. fracking boom.

"It's a hellacious problem," said Hugh Ray, a bankruptcy lawyer with McKool Smith in Houston. "It will end with even more bankruptcies."

A judge on New York's influential bankruptcy court said on Feb. 2 she was inclined to allow Houston-based Sabine to end its pipeline contract, which guaranteed it would ship a minimum volume of gas through a system built by a Cheniere Energy (LNG.A) subsidiary until 2024. Sabine's lawyers argued they could save $35 million by ending the Cheniere contract, and then save millions more by building an entirely new system.

Fort Worth, Texas-based Quicksilver's request to shed a contract with another midstream operator, Crestwood Equity Partners (CEQP.N), is set for Feb. 26.

The concerns have grown more evident in recent days, raised in law firms' client memos and investment bank research notes.

Last week, executives from Williams Companies Inc (WMB.N) and Enbridge Inc (ENB.TO), two of the world's largest pipeline operators, sought to allay growing investor fears, saying they were reviewing contracts or securing additional credit guarantees to minimize the impact of the biggest oil bust in a generation.

So far, relatively few oil and gas producers have entered bankruptcy, and most were smaller firms. But with oil prices down 70 percent since mid-2014 and natural gas prices in a prolonged slump, up to a third of them are at risk of bankruptcy this year, consultancy Deloitte said in a Feb. 16 report.

http://www.reuters.com/article/us-usa-oil-lawsuits-idUSKCN0VV0DK

Pacific Exploration & Production Corp. said holders of a minority of its bonds agreed to hold off on demanding immediate repayment after the driller missed interest payments due last month.

Holders of 42 percent of the 2025 bonds agreed to the extension after a 30-day grace period expire d on a missed January interest payment, according to the statement published Friday. Holders of 34 percent of the 2019 bonds, the grace period on which ends next week, also agreed to the extension. Remaining investors would need the support of 25 percent of a series of notes in order to accelerate the securities, according to the prospectus.

The Bogota-based driller, which trades in Canada and Colombia, is one of the largest independent oil and gas explorers in Latin America. Founded a decade ago by veterans of Venezuela’s oil industry, the company is struggling after crude prices sank to a 12-year low and the contract at its biggest field wasn’t extended past June.

“The extension should allow the company additional time to continue working with the independent committee of the Board of Directors, the company’s financial and legal advisors as well as its lenders and the noteholders to come to a consensual and comprehensive restructuring of the company’s balance sheet,” Chief Executive Officer Ronald Pantin said, according to the statement.

A 30-day grace period after a missed January payment on the 2025 bonds expired Thursday.

Pacific said it’s also in the process of entering into forbearance agreements with its bank lenders. The company’s benchmark $1.3 billion of bonds due 2019 are trading at about 13 cents on the dollar.

Buyout firm EIG Global Energy Partners is offering to buy Pacific’s distressed bonds for 16 cents on the dollar with no accrued interest. While that’s less than a previous bid in January of 17.5 cents plus interest that failed to get much support, EIG says investors would be wise to take the offer as Pacific’s finances will deteriorate further.

Standard & Poor’s lowered the company’s rating to D last month, saying it considered a default to have occurred because it didn’t see the interest being paid within the grace period. S&P said it expected Pacific “to enter into a general default and that it will fail to pay all or substantially all of its obligations as they come due.”

http://www.bloomberg.com/news/articles/2016-02-19/pacific-misses-debt-payment-says-some-investors-grant-extension

Cheniere Energy said it has started producing LNG from the first liquefaction train at its Sabine Pass LNG export terminal in Louisiana.

“Train 1 has begun producing LNG, and the first LNG commissioning cargo is expected to be exported late February or March,” Cheniere said in its fourth-quarter results report on Friday.

The first commissioning cargo from the liquefaction and export facility in Cameron Parish, Louisiana was initially expected to occur by late January. The cargo was delayed due to instrumentation issues that were discovered during the final phases of plant commissioning.

Commissioning for Train 2 at the Sabine Pass plant is expected to commence in the upcoming months, according to Cheniere.

Cheniere is building liquefaction and export facilities at its existing import terminal located along the Sabine Pass River on the border between Texas and Louisiana.

The company plans to construct over time up to six liquefaction trains, which are in various stages of development. Each train is expected to have a nominal production capacity of about 4.5 mtpa of LNG.

Cheniere’s Sabine Pass liquefaction facility will be the first of its kind to export cheap and abundant U.S. shale gas to overseas markets.

Net loss widens

Cheniere reported a net loss of $291 million for the fourth quarter of 2015, compared to a net loss of $159 million for the comparable 2014 period.

For the full- year 2015, the company posted a net loss of $975 million, compared to a net loss of $548 million a year before.

http://www.lngworldnews.com/cheniere-sabine-pass-train-1-starts-producing-lng/

An excellent article appearing on the World Oil Magazine website explores an interesting phenomenon at work in the Marcellus/Utica. The article is wide-ranging and provides an update on the activities and strategies for many of our region’s top producers. But the beginning of the article is what really caught our attention.

The author states that there is a shift happening away from drilling in the liquids-rich (i.e. areas with a higher concentration of natural gas liquids, like ethane, propane and others) to the “core” dry gas areas of the Marcellus/Utica. He quotes Rice Energy CEO Dan Rice in saying, “…there has been a noticeable shift in producer activity away from liquids-rich and non-core dry gas Marcellus and Utica areas, and into the Marcellus and Utica’s dry gas cores.”

We have to confess that’s the first time we’d heard that. We thought it was the reverse–that there was more drilling headed to the wet gas areas. Huh.

 http://marcellusdrilling.com/2016/02/drillers-leaving-wet-gas-areas-of-marcellusutica-for-dry-gas/?utm_source=dlvr.it&utm_medium=twitter

What did Chevron accomplish in 2015 by outspending cash flow by $19 billion?

Increase production a paltry 2%. Barely replace reserves-107% of production.

That is what Chevron managed to achieve in 2015 by spending $31 billion while generating just $19 billion of cash flow. And that is actually incredibly bullish, despite the fact that the oil price has come down hard already in 2016.

Investor sentiment-from both the shareholders and the lenders-is forcing ALL producing companies to move closer to spending within cash flow.

What would Chevron's production and reserve growth look like if they do that? I'm guessing it would be MUCH less.

Their capex in 2016 is going down 22% $26.6 billion, but the savior for the company in 2015-its downstream refinery business-is getting crushed right now.

Refinery margins were huge through most of 2015-they contributed $7.6 billion in profits to Chevron in 2015-but crack spreads have recently fallen a lot. And with a glut of some 160 million barrels of refined products in the USA, that won't change much this year. (I got short refineries in January.)

This all reads like bad news, but it's actually very bullish. These numbers say how far the oil price must go up for western companies to make money. And now asset sales are slow, and lowly priced (everyone is a seller), debt is being reined in and equity is a non-starter for all but the best companies.

If That Was 2015 What Is 2016 Going To Look Like?

If you want the truth you have to look directly at the numbers.

Chevron's Q4 and full year 2015 numbers speak volumes. They tell us that something has to give. And as I show you at the bottom here, that may be happening now. In Q4, they generated $4.6 billion in cash flow, and spent $9.4 billion on capital and dividends.

Here is how the full year 2015 cash inflows and outflows look for Chevron:

In Billions                                         2015                   2014
Cash Generated By Operations     $19.5                  $31.5
Capital Expenditures                     ($30.6)               ($36.8)
Dividends Paid                                ($8.0)                 ($7.9)
Share Repurchases                         $0.0                   ($4.4)
Net Cash Outflow                          ($19.1)                ($17.6)


It isn't a pretty picture.

Course summary This module is designed for people interested in the exploration and production of oil and gas who do not have a subsurface technical background. It provides a brief introduction to geology and geophysics for non-ge...

When you include both capex spending and cash required for its dividends, Chevron spent $38.6 billion while generating only $19.5 billion from operations.

That is a net cash outflow of $19.1 billion!

Talk about living beyond your means. The obvious question is how did Chevron finance all of this outspending?

Well, they did it like anyone who lives beyond their means would.

First they dipped into their savings.

Chevron's cash and net working capital balances decreased by $2.6 billion in 2015.

Then they borrowed.

In 2015 Chevron's long term debt increased by $10.8 billion. That is an increase from $27.8 billion to $38.6 billion in total debt.

And then they started selling off some of their belongings.

Proceeds from asset sales in 2015 totaled $5.7 billion.

By massively outspending cash flow, running up debt on its balance sheet and selling assets Chevron managed to maintain its dividend and keep its production basically flat. (At least they didn't spend any money on share buybacks, like the $4.4 billion they did in 2014. Watching these companies buy back stock during the good times when the stock prices are high and then buy back none now must be irksome to more than a few shareholders.)

If Chevron had lived within cash flow, you have to wonder what the dividend might have been and what production and reserve growth would have looked like.

It is not a pretty picture. 2016 is shaping up to be significantly worse considering that oil prices in 2015 were on average $20 per barrel higher than where they sit today.

Last year would have been much worse for Chevron if the company didn't have its own refineries. Chevron's downstream operation (refineries=downstream, pipelines=midstream, producers=upstream) actually benefits from low oil prices and that helped significantly cushion the blow.

Chevron's downstream operations recorded a profit of $7.6 billion in 2015. Without that this company would be in far worse shape.

The Real Battle Is The Fed (Not The Shale Producers) Vs The Saudis

This is what life looks like for Chevron. A company with a very mature low decline production base and the benefit of a profitable downstream operation.

No wonder the shale guys are feeling so much pain. They have young, very high decline production and no diversifying downstream business segment.

Seeing how Chevron allowed its balance sheet to deteriorate in 2015 once again underscores the point....

The biggest threat to the Saudis is not from the shale producers, it is from the Federal Reserve and its ZIRP (zero interest rate policy). Can you imagine Chevron allowing its long term debt to increase by nearly 40% in just one year if interest rates were at 8%?

Chevron's massive outspending in 2015 is how the shale boom was built right from the start. The shale producers had access to billions and billions of dollars of low cost funding.

Low oil prices have ended that party. Reasonable interest rates would have done the same.

What is abundantly clear is that 2016 is going to be a year of very hard decisions for a lot of people in this industry. For Russia and OPEC it is about cutting production.

For Chevron, that hard decision could involve its dividend. If Chevron completely eliminated its dividend in 2015 it would still have outspent cash flow in by $11 billion. That was with considerably higher oil prices.

http://www.oilvoice.com/n/These-Numbers-Show-How-High-Oil-Must-Goand-Fast/89acc1a0d5aa.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

The total number of active, producing oil wells in the U.S. dropped slightly during 2015, a trend that looks set to sharpen this year, as the oil price decline begins to exact its toll on the industry. According to World Oil’s forecast data, the total number of active oil wells declined to 594,436 from 597,281, a 0.5% decline.

http://www.worldoil.com/magazine/2016/february-2016/special-focus/producing-oil-wells-tick-down-as-price-begins-to-hit

The global oil market is over-supplied by around 1.8 million barrels per day (bpd), but that glut could be halved if a deal to freeze oil production at last month's levels takes effect, a top Russian energy official said on Friday.

Leading OPEC member Saudi Arabia, non-OPEC member Russia, Qatar and Venezuela this week agreed to freeze output at January levels if others joined in. Iran welcomed the move but stopped short of pledging to act itself and it is unclear whether the freeze will actually happen.

"If the agreement is properly fulfilled and it definitively enters into force then around half of that excess supply may be removed from the market," Alexey Texler, Russia's first deputy energy minister, told reporters in the Siberian city of Krasnoyarsk.

"Even without Iran there will be an effect from the agreement. But Iran ... might also be interested in such a deal," he said, noting Tehran had a choice of increasing output at a time of falling prices, or joining the production freeze and potentially getting a higher price for current volumes.

"We are optimistic," he added.

Russia and OPEC were both pumping oil at near record volumes last month, with Russia reaching another post-Soviet high of 10.88 million bpd.

"We are talking about freezing January production levels. It would be higher than the annual average for 2015 by around 1.5 percent," Texler said. Oil production in Russia last year averaged 10.72 million bpd.

The first mooted global oil pact in 15 years will depend on other producers, but it remains unclear which other countries need to sign up for the deal to be implemented.

Asked if Russia will talk to the United States, Brazil, Mexico and Norway, Texler said: "Any country may join. But we are realists and, in general, we understand which countries it will be. Many of those you named, obviously, will not do that."

He added that some producers, still, were uniting round the idea. Texler did not name them.

"We consider such an agreement useful and necessary. It will allow us to forecast the output volumes of key market players, and such an agreement will allow to continue the market process of influencing expensive projects."

The Russian oil industry would "move forward" at a price of $35-40 per barrel this year, Texler said. Earlier on Friday, he said that investment in the Russian energy sector was likely to be lower this year than in 2015.

http://www.reuters.com/article/russia-oil-texler-idUSL8N15Y2GI

Russian President Vladimir Putin and members of his Security Council exchanged views on the situation on global oil markets as Russia's Energy Ministry holds contacts with foreign partners, Interfax quoted the Kremlin's spokesman as saying on Friday.

Russia and Saudi Arabia, along with two other countries, agreed this week to freeze oil output at January levels if other countries joined in.

Dmitry Peskov, the Kremlin spokesman, told reporters earlier there was no link between Syria and oil production in Russia's dialogue with Saudi Arabia.

http://www.reuters.com/article/mideast-crisis-oil-idUSR4N12X02S