Saudi Arabia will supply more Arab Extra Light crude to at least two buyers in Asia in July, four sources familiar with the matter said on Thursday, as the top oil exporter ramps up shipments in a bid to claim a bigger share of the Asian market.

Saudi Arabia has traditionally accounted for most of the crude imports by Asia, the world's biggest oil consuming region, but recently its position has been challenged with Russia overtaking it as China's top supplier in the past three months.

The kingdom, however, has responded by pumping and shipping more following an oilfield expansion, a move that traders say could pressure rival producers - such as the United Arab Emirates (UAE) and Russia - and knock down prices in Asia.

In fact, state oil giant Saudi Aramco has already found buyers for its additional output in July, with some customers in Asia lifting 10 percent more than contracted volumes, the sources told Reuters on Thursday.

The OPEC kingpin kept the official selling price (OSP) for Arab Extra Light unchanged in July, contrary to expectations for a hike, to accommodate a 33 percent rise in output from an expansion at the Shaybah oilfield.

"They are really pushing hard," a trader with a North Asian refiner said.

Saudi Arabia could next cut OSPs for August to retain its competitive edge over rivals during what is expected to be a season for weak demand in Asia as several refineries shut for maintenance in the third quarter.

Already, a near doubling of Asia's crude benchmark Dubai DUB-1M-A from the first quarter has depressed Asian refining margins. The resultant low demand has hit values for rival light grades like UAE's Murban and Russian ESPO.

"UAE would be most affected if Saudi boosted sales," a second Asian crude buyer said.

Murban MUR-1Madn- cargoes loading in August sold at discounts against their OSP, while ESPO premiums ESPO-DUB were mostly below $2 a barrel against Dubai quotes, the lowest in at least eight months.

"China used to be the biggest buyer (of ESPO crude) but they have slowed down a lot," a Singapore-based trader said.

http://www.reuters.com/article/asia-crude-saudi-idUSL4N19J3GG

Saudi Arabia, the world’s largest crude exporter, cut all official selling prices for its crude sales to Asian and U.S. clients in August.

State-owned Saudi Arabian Oil Co. lowered its official selling price for Arab Light crude to Asia by 40 cents to a premium of 20 cents a barrel above a regional benchmark, the company known as Saudi Aramco said in an e-mailed statement Thursday. The company had been expected to cut the premium for shipments of Arab Light crude by 25 cents to 35 cents a barrel more than the benchmark for buyers in Asia, according to the median estimate in a Bloomberg survey of seven refiners and traders in the region.

Brent crude has dropped more than 35 percent since Saudi Arabia led a 2014 decision by the Organization of Petroleum Exporting Countries to maintain production to drive out higher-cost producers. The group decided to stick to its policy of unfettered production at its June 2 meeting in Vienna, with ministers united in their optimism that global oil markets are improving.

Saudi Arabia considers the global oil glut to be over, its Energy Minister Khalid Al-Falih told the Houston Chronicle in an interview this month. The comments echo views of the International Energy Agency, which said on June 14 that the crude market will be balanced in the second half.

All other official selling prices for Asian clients were also reduced, the statement showed. The biggest cut was by 90 cents a barrel for Extra Light, to a premium of $1.70 a barrel above an Oman/Dubai benchmark. U.S. prices were all lowered compared with July. Again, the largest reduction was Extra Light. Its premium was lowered to $1.70 a barrel above its benchmark, compared with $2.10 for July.

Middle Eastern producers are competing with cargoes from Latin America, North Africa and Russia for buyers in Asia, its largest market. Producers in the Persian Gulf region sell mostly under long-term contracts to refiners. Most of the Gulf’s state oil companies price their crude at a premium or discount to a benchmark. For Asia the benchmark is the average of Oman and Dubai oil grades.

http://www.bloomberg.com/news/articles/2016-06-30/saudi-aramco-cuts-all-august-oil-prices-for-u-s-asian-clients

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One of the pillars of oil’s recovery from the lowest price in 12 years may be on the verge of crumbling.

China is likely close to filling its strategic petroleum reserves after doubling purchases for it this year as prices plunged, JPMorgan Chase & Co. analysts including Ying Wang wrote in a June 29 research note. Stopping shipments for the reserve would wipe out about 15 percent of the country’s imports, according to the bank.

Chinese crude imports have risen 16 percent this year, and the country is rivaling the U.S. as the world’s biggest oil purchaser. That demand, along with supply disruptions from Canada to Nigeria, has helped boost oil prices about 80 percent since January.

“China has taken the opportunity of lower oil prices since early-2015 to accelerate the strategic petroleum reserve builds,” Wang said in the report. “This volume might be close to the capacity limit, in our view, and together with potential teapot utilization pullback and slower-than-expected demand from China could increase near-term risks to global oil prices.”

Chinese imports surged to a record 8.04 million barrels a day in February. The nation may surpass the U.S. as the world’s largest crude importer this year with average inbound shipments of 7.5 million barrels a day, according to Zhong Fuliang, vice president with China International United Petroleum & Chemicals Co., the trading arm of the nation’s biggest refiner.

Second-Phase

China finished building the first phase of its strategic petroleum reserve program with four sites in 2009, totaling 91 million barrels, according to the National Bureau of Statistics. The second-phase will be completed by 2020, according to the 2016-2020 Five Year Plan released in March.

The Chinese government doesn’t regularly report the capacity or storage level of its strategic reserves. JPMorgan calculated the surplus crude available to go into the SPR by subtracting how much oil is refined into fuels or sent to commercial inventories from the combined volume of the domestic crude output and net imports. The surplus is about 1.2 million barrels a day this year, up from 491,000 last year, and adds up to about 400 million barrels in total, the bank estimates.

The bank assumes the capacity for the reserves is about 511 million barrels, based on government plans cited by state media. At the current rate of stockpiling, the storage would fill up by August, leading to a potential import drop in September.

“We do not believe the 16 percent growth in oil imports year-to-date is sustainable despite a domestic oil production decline, as demand is weak, if inventory capacity reaches the limit,” the bank said.

http://www.bloomberg.com/news/articles/2016-06-30/oil-bulls-beware-because-china-s-almost-done-amassing-crude

OPEC's oil output has risen in June to its highest in recent history, a Reuters survey found on Thursday, as Nigeria's oil industry partially recovers from militant attacks and Iran and Gulf members boost supplies.

Higher supply from major Middle East producers except Iraq underlines their focus on market share. Talks in April between producers on freezing output failed and have not been revived as a recovery in prices to $50 a barrel reduces the urgency to prop up the market.

Supply from the Organization of the Petroleum Exporting Countries has risen to 32.82 million barrels per day (bpd) this month, from a revised 32.57 million bpd in May, the survey based on shipping data and information from industry sources found.

That June output figure would be less than the average demand OPEC expects for its crude in the third quarter, suggesting demand could exceed supply in coming months if OPEC does not pump more than current levels.

"We could see a slight supply deficit - it depends on further development of unplanned outages," said Carsten Fritsch, analyst at Commerzbank in Frankfurt.

OPEC's June output exceeds January's 32.65 million bpd, when Indonesia's return as an OPEC member boosted production and output from the other 12 members was the highest in Reuters survey records, starting in 1997.

Supply has surged since OPEC abandoned in 2014 its historic role of cutting supply to prop up prices.

The biggest increase in June of 150,000 bpd came from Nigeria, where output had fallen to its lowest in more than 20 years due to militant attacks on oil facilities, due to repairs and a lack of major new attacks since mid-June.

Iran managed a further supply increase after the lifting of Western sanctions in January, sources in the survey said, although the pace of growth is slowing.

Gulf producers Saudi Arabia and the United Arab Emirates increased supply by 50,000 bpd each, the survey found. Saudi output edged up to 10.30 million bpd due to higher crude use in power plants to meet air-conditioning needs.

"Exports are fairly flat, refinery runs are flat and crude direct burn is up, so directionally supply is up from May," said an industry source who monitors Saudi output.

Libyan output rose by 40,000 bpd after the reopening in late May of the Marsa al Hariga export terminal, the survey found. Supply is still a fraction of the pre-conflict rate.

Among countries with declining supply, Iraq pumped less for a second month. Exports in the south of the country have been trimmed by maintenance work, power cuts and higher domestic demand, Iraqi officials say.

Venezuela's supply is under downward pressure from its cash crunch.

The Reuters survey is based on shipping data provided by external sources, Thomson Reuters flows data, and information provided by sources at oil companies, OPEC and consulting firms.

http://www.reuters.com/article/us-opec-oil-survey-idUSKCN0ZG1X5

Chevron Corp. may shortly give a green light to the most expensive oil project in the world this year as the industry digs out from the worst slump in a generation.

The company said this week in a presentation on its website that the decision on expanding the Tengiz development in Kazakhstan will be made in mid-2016. Installing 4,500 camp beds for construction crews is done and port dredging 25 percent complete, it said. The project may cost as much as $40 billion and add crude supply equivalent to that of Libya. The investment was put on hold last year after cost estimates ballooned amid plunging oil prices.

In a May interview, Kazakh Energy Minister Kanat Bozumbayev predicted a late-June approval and estimated the cost at $36 billion to $37 billion. Wood Mackenzie Ltd. said it could reach $40 billion. Chevron spokesman Kurt Glaubitz declined to comment on the pace of the Chevron board’s deliberations or the projected price tag.

“This is very big and very important for Chevron and for Kazakhstan,’’ said Matthew Sagers, the Washington-based managing director of Russian and Caspian energy research at consulting firm IHS Inc. “It shows that the situation is now turning in the oil market that people are putting down this kind of money.’’

The Tengiz expansion would come after oil explorers around the globe slashed more than $1 trillion in investments to weather a downturn that saw U.S. crude tumble 75 percent from June 2014 to last February. Hundreds of thousands of drillers, engineers and geologists were fired and the contagion spread to steel mills, trucking and lodging companies. The project represents a bullish bet that oil demand will continue to grow through the next decade and beyond, according to IHS.

For Chevron, the squeeze meant writing off hundreds of millions of barrels of deepwater discoveries in the U.S. Gulf of Mexico and elsewhere. The San Ramon, California-based explorer slashed annual spending plans for 2017 and 2018 to between $17 billion and $22 billion each year, a reduction of about 26 percent from this year.

Chevron’s 50 percent ownership interest in Tengiz means it has more at stake than its partners: Exxon Mobil Corp., Kazmunaigaz National Co. and Lukoil PJSC. The field already accounts for almost one-fifth of Chevron’s worldwide oil production.

Tengiz Production

Tengiz produced about 595,000 barrels a day last year, according to Tengizchevroil, the partnership that operates the field. The expansion will involve pumping sulfur-laden gas back into the rocks to force out an additional 250,000 to 300,000 barrels a day.

“Tengiz has been very lucrative for Chevron for many years,’’ said Brian Youngberg, an analyst at Edward Jones & Co. in St. Louis, who has a “buy’’ rating on the shares. “It’s one of the few projects in that part of the world that worked as planned.’’

It’s also the only major new project Chevron spared from the austerity budget imposed this year to cope with the slump in crude prices and cash flow. The partnership probably will issue bonds or otherwise tap lenders to finance the expansion, Chairman and Chief Executive Officer John Watson told analysts and investors at the company’s annual strategy presentation in March.

Technically Challenging

Discovered in 1979, Tengiz was too technically challenging for Soviet engineers to develop. A blowout in a well called T-37 in June 1985 blazed for more than 400 days before it was extinguished by U.S. well-control experts, according to a history of the field published by Tengizchevroil.

Chevron won the rights to develop the field in 1993 after the collapse of the Soviet Union. Tengiz produces a very light form of crude oil, highly prized by refiners because of its high gasoline yield, Sagers of IHS said.

The Tengiz expansion probably will begin pumping barrels in 2021 or 2022, said Samuel Lussac, research manager for Caspian upstream oil and gas at Wood Mackenzie in Edinburgh. The combination of new Tengiz supplies and output from the Kashagan project set to come online later this year could boost Kazakhstan’s daily output to more than 2 million barrels, vaulting it past countries including Norway and Qatar.

“This will be like another small producing nation coming online,’’ Sagers said.

Chevron classifies the Tengiz expansion as one of just 13 major capital projects in the company’s portfolio spread across five continents, according to a June 28 presentation published on its website.

“Kazakhstan is right at the top for them in the world,’’ Youngberg said.

http://www.bloomberg.com/news/articles/2016-06-30/chevron-deadline-nears-for-40-billion-bet-on-next-decade-s-oil

Gazprom's gas sales in Europe in the first half of 2016 rose by 14.2%, or 10.6 Bcm, compared with the same period of last year, Gazprom CEO Alexei Miller said Thursday, signaling a sharp slowdown in export growth in the second quarter of this year.

Addressing Gazprom's annual general meeting in Moscow, Miller also hailed the utilization rate of Russia's Nord Stream gas pipeline to Europe, which, he said, far outweighed that of LNG imports.

Speaking of Gazprom's supplies to Europe and Turkey in the first half, Miller provided no absolute figures.

But according to Platts' analysis of Gazprom data, a 10.6 Bcm increase on the 74.3 Bcm sold in Europe and Turkey (excluding the former Soviet Union states) in the first half of 2015 means H1 2016 sales of 84.9 Bcm.

This puts Gazprom well on track to reach its most recently stated target from May of total exports to Europe and Turkey in 2016 of 165 Bcm.

However, the 10.6 Bcm increase in the first half confirms that the growth in Gazprom's gas sales to its core foreign markets stalled in the second quarter after strong growth at the start of the year.

In the first quarter, Gazprom's sales in Europe and Turkey were up 10 Bcm on the same period of 2015, meaning that supply growth was just 0.6 Bcm in Q2.

In the first quarter of 2016, sales to Europe and Turkey totaled 44.4 Bcm, according to official Gazprom data, which was up 29% from 34.4 Bcm in Q1 2015.

This suggests Q2 sales of 40.5 Bcm.

"The share of import gas in European consumption currently amounts to nearly 50%," Miller said.

"Europe's demand for additional imports will grow by no less than 100 Bcm/year by 2025, and can rise to 150 Bcm/year by 2035," Miller said.

He said that data from 2015 showed that trunk gas pipeline supply enjoys greater demand than LNG in Europe.

"While only one quarter of European LNG capacity was utilized last year, gas deliveries via Nord Stream grew despite regulatory [restrictions]," he said, a likely reference to the constraints on the use of the OPAL gas pipeline in eastern Germany. Under a 2009 decision by German energy regulator Bundesnetzagentur and approved by the European Commission, Gazprom is limited to using a maximum 50% of the capacity of the 36 Bcm/year OPAL pipeline, which connects the Nord Stream to the European pipeline grid.

http://www.platts.com/latest-news/natural-gas/moscow/gazprom-h1-gas-exports-to-europe-up-14-year-on-26482146

Subsidiaries of China's second-largest energy company Sinopec inflated their 2014 revenue and costs by 20.2 billion yuan ($3.04 billion), according to a report published by China's auditing department.

Twelve subsidiaries of Sinopec Group, the parent of Sinopec Corp, have manipulated their financial reports by creating fake invoices of fuel sales, among other discrepancies, the report from the China National Audit Office published on Wednesday said.

The audit also showed Sinopec lost 1.29 billion yuan after it acquired a 49-percent stake in an overseas project, due to "insufficient assessment of risk factors," said the report, without identifying the project.

Crude output from 29 overseas production projects fell short of targets stated in feasibility studies by about 90 million tonnes, the audit showed.

Sinopec compared the audit to a health screening in a statement it released on Wednesday in response to the report.

"Of the 31 problems reported in the audit, we've completed the rectifying of 28 and the remaining three is under way," the company said.

Sinopec Group's listed vehicle Sinopec Corp reported it earned 2,825.9 billion yuan ($425 billion) in revenue and reported costs of about 2,566 billion yuan ($386.17 billion) in 2014.

China's national audit department reviewed the financials of the 10 largest state-owned companies including Aluminium Corporation of China (CHALCO), Sinopec and China National Offshore Oil Corporation (CNOOC), exposing huge losses in these firms as a result of low efficiency and bad investment decisions.

The auditing office also pointed to wasted investments Sinopec's subsidiaries made, such as 14 unused chemical plants, and raised red flags on two dozen "illegally acquired" fuel stations.

The agency also said Sinopec added refining capacities faster than the market could absorb, leading to underutilization of facilities.

By contrast, an audit carried out on CNOOC, a state-run offshore oil producer, found only minor problems such as slow progress in projects.

http://www.reuters.com/article/us-sinopec-revenue-idUSKCN0ZG18L

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Nigeria has signed oil and gas infrastructure agreements worth $80 billion with Chinese companies, the West African country's state oil company said on Thursday.

Nigeria, an OPEC member which was until recently Africa's biggest oil producer, relies on crude sales for around 70 percent of national income, but its oil and gas infrastructure is in need of updating.

The country's four refineries have never reached full production because of poor maintenance, causing it to rely on expensive imported fuel for 80 percent of energy needs.

These problems have been exacerbated by a series of attacks on oil and gas facilities by militants in the southern Niger Delta energy hub which pushed production down to 30-year lows in the last few weeks.

Oil minister Emmanuel Ibe Kachikwu, who also heads the Nigerian National Petroleum Corporation (NNPC), has been in China since Sunday for a roadshow aimed at raising investment.

"Memorandum of understandings (MoUs) worth over $80 billion to be spent on investments in oil and gas infrastructure, pipelines, refineries, power, facility refurbishments and upstream have been signed with Chinese companies," said NNPC in a statement.

NNPC added the China roadshow was "the first of many investor roadshows intended for the raising of funds" to support the country's oil and gas infrastructure development plans.

Earlier this week, NNPC said oil production had in the last few days risen by around 300,000 barrels per day (bpd) to 1.9 million bpd, due to repairs and no attacks having been carried out since June 16.

Goldman Sachs, in a report published on Wednesday, said a "normalization" in Nigerian oil production would put pressure on global oil prices and may mean prices will average less than $50 a barrel during the second half of 2016.

http://www.reuters.com/article/nigeria-oil-idUSL8N19M2HO

The newly expanded Panama Canal will be able to accommodate 90% of the world's current liquefied natural gas (LNG) tankers with LNG-carrying capacity up to 3.9 billion cubic feet (Bcf). Prior to the expansion, only 30 of the smallest LNG tankers (6% of the current global fleet) with capacities up to 0.7 Bcf could transit the canal. The expansion has significant implications for LNG trade, reducing travel time and transportation costs for LNG shipments from the U.S. Gulf Coast to key markets in Asia and providing additional access to previously regionalized LNG markets.

The new locks in the canal provide access to a wider lane for vessels and are 180 feet across, compared with 109 feet in the original locks. Only the 45 largest LNG vessels, 4.5-Bcf to 5.7-Bcf capacity Q-Flex and Q-Max tankers used for exports from Qatar, will not be able to use the expanded canal.

Transit through the Panama Canal will considerably reduce voyage time for LNG from the U.S Gulf Coast to markets in northern Asia. Four countries in northern Asia—Japan, South Korea, China, and Taiwan—collectively account for almost two-thirds of global LNG imports. A transit from the U.S. Gulf Coast through the Panama Canal to Japan will reduce voyage time to 20 days, compared to 34 days for voyages around the southern tip of Africa or 31 days if transiting through the Suez Canal. Voyage time to South Korea, China, and Taiwan will also be reduced by transiting through the Panama Canal.

The wider Panama Canal will also considerably reduce travel time from the U.S. Gulf Coast to South America, declining from 20 days to 8-9 days to Chilean regasification terminals, and from 25 days to 5 days to prospective terminals in Colombia and Ecuador. For markets west of northern Asia, including India and Pakistan, transiting the Panama Canal will take longer than either transiting the Suez Canal or going around the southern tip of Africa.

In addition to shortening transit times, using the Panama Canal will also reduce transportation costs. The Panama Canal Authority has introduced new toll structures for LNG vessels designed to encourage additional LNG traffic through the Canal, especially for round trips. Transit costs through the Panama Canal for an average 3.5 Bcf LNG carrier are estimated at $0.20 per million British thermal units (MMBtu) for a round-trip voyage, representing about 9% to 12% of the round-trip voyage cost to countries in northern Asia.

Based on IHS data, the round trip voyage cost for ships traveling from the U.S. Gulf Coast and transiting the Panama Canal to countries in northern Asia is estimated to be $0.30/MMBtu to $0.80/MMBtu lower than transiting through the Suez Canal and $0.20/MMBtu to $0.70/MMBtu lower than traveling around the southern tip of Africa. Transiting the Panama Canal offers reduction in transportation costs to northern Asian countries such as Japan, South Korea, Taiwan, and China and may offer some minimal cost reductions to countries in southeast Asia (Malaysia, Thailand, Indonesia, and Singapore), depending on transit time. U.S. LNG exports to India, Pakistan, and the Middle East are not expected to flow through the Panama Canal because alternative routes, either the Suez Canal or around the southern tip of Africa, have lower transportation costs.

Currently, about 9.2 billion cubic feet per day (Bcf/d) of U.S. natural gas liquefaction capacity is either in operation or under construction in the United States. By 2020, the United States is set to become the world's third-largest LNG producer, after Australia and Qatar. More than 4.0 Bcf/d of U.S. liquefaction capacity has long-term (20 years) contracts with markets in Asia, of which 3.2 Bcf/d is contracted to Japan, South Korea, and Indonesia.

An additional 2.9 Bcf/d of U.S. liquefaction capacity currently under construction has been contracted long-term to various countries. Flexibility in destination clauses allows these contracted volumes to be taken to any LNG market in the world. Assuming all contracted volumes transit the Panama Canal, EIA estimates that LNG traffic through the Canal could reach more than 550 vessels annually, or 1-2 vessels per day, by 2021.

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Norway oil wage talks begin could affect 6% of production

Energy companies and trade unions in Norway began two-day wage talks on Thursday in a bid to avert a strike that would cut output from Europe's largest oil producer by 6 percent, the Norwegian Oil and Gas Association (NOG) said.

Oil and gas production at five offshore fields could be shut from July 2 if no compromise is found, NOG said, and the strike could spread subsequently.

The five fields are ExxonMobil's Balder, Ringhorne and Jotun, Engie's Gjoea and Wintershall's Vega.

That would cut Norway's output by 229,000 barrels of oil equivalents per day, said NOG, which negotiates on behalf of the energy firms.

Hundreds of workers on eight oil platforms operated by Norway's Statoil would also strike but output would be maintained, NOG said.

About 755 workers would go on strike initially, while a protracted conflict could eventually affect more than 7,400 workers, data from the mediator's office showed.

Rules governing labor disputes in Norway give the government the power to force an end to strikes under certain conditions, including when national interests are considered to be at stake.

http://www.reuters.com/article/us-norway-oil-strike-idUSKCN0ZG130

Exxon Mobil Corporation today said that drilling results from the Liza-2 well, the second exploration well in the Stabroek block offshore Guyana, confirm a world-class discovery with a recoverable resource of between 800 million and 1.4 billion oil-equivalent barrels.

'We are excited by the results of a production test of the Liza-2 well, which confirms the presence of high-quality oil from the same high-porosity sandstone reservoirs that we saw in the Liza-1 well completed in 2015,' said Steve Greenlee, president of Exxon Mobil Exploration Company. 'We, along with our co-venturers, look forward to continuing a strong partnership with the government of Guyana to further evaluate the commercial potential for this exciting prospect.'

The Liza wells are located in the Stabroek block approximately 120 miles (193 kilometers) offshore Guyana. Data from the successful Liza-2 well test is being assessed.

The Liza-2 well was drilled by ExxonMobil affiliate Esso Exploration and Production Guyana Ltd., approximately 2 miles (3.3 km) from the Liza-1 well. The Liza-2 well encountered more than 190 feet (58 meters) of oil-bearing sandstone reservoirs in Upper Cretaceous formations. The well was drilled to 17,963 feet (5,475 meters) in 5,551 feet (1,692 meters) of water.

'This exploration success demonstrates the strength of our long-term investment approach, as well as our technology leadership in ultra, deepwater environments,' said Greenlee.

The Stabroek block is 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Nexen Petroleum Guyana Limited holds 25 percent interest.

http://www.oilvoice.com/n/ExxonMobil-confirms-significant-oil-discovery-offshore-Guyana/3858086d06d1.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Soaring east coast gas prices due to the cold snap and rising demand from the Queensland LNG projects have triggered fears among manufacturers about a Tasmanian-style energy crisis that would lead to losses.

The first prolonged period of chilly temperatures this winter stretching along the east coast has come just after the start up of the fifth of Queensland's six LNG export trains and has driven short-term wholesale prices sharply higher over the past week.

Wholesale gas prices in Sydney for Thursday reached almost $29 a gigajoule, about 60 per cent higher than their peak in 2012.

The spike means industrial gas buyers relying on the short-term market for part of their supplies will be paying more than three times as much as Japan is paying for importing LNG.

The price squeeze has raised fears among gas buyers that they are one step away from being asked to cut back their consumption to preserve supplies for households, just as industrial electricity users had to in the recent Tasmanian hydro-power crisis.

"In a worst-case situation we would be asked to offload, and the community then has really got to make the decision do they want to keep people in work or do they want to keep their houses heated," said Brickworks managing director Lindsay Partridge, recalling just such a situation in southern California in the early 1980s.

"The reason of course the price is up is because there's a shortage, so if there was an extended cold snap or there was some minor outage it would ricochet across the entire east coast very rapidly,"

Ben Eade, executive director of Manufacturing Australia, said the combined impact of the cold and the fifth LNG train starting up in Gladstone was placing "significant pressure" on short-term domestic gas markets, just as gas buyers had been warning.

"It's not just about the spiking prices: large gas users remain concerned about the risk to their operations of gas curtailment if sudden demand spikes exceed available supply on very cold days," Mr Eade said.

Last Friday saw the first cold weather-driven demand "event", as termed by the Australian Energy Market Operator, when the spot gas price in Victoria exceeded $20 a gigajoule for a four-hour period. Prices spiked on Wednesday in Brisbane, reaching $11.95, while prices in Adelaide recently touched $18.99.

Historically, wholesale prices were typically $3-$4 a gigajoule, although in recent years contract tariffs have risen to $6-$8 a gigajoule or higher, if they can be secured at all.

Mr Partridge said Brickworks had only been able to lock in gas supplies to the end of 2017.

"No one will write you a contract beyond 2018 at any price, so that makes things very concerning," he said.



Read more: http://www.afr.com/business/energy/gas/soaring-gas-prices-trigger-fears-of-tasmaniastyle-energy-crisis-20160629-gpv46w#ixzz4D4ZPS9OO
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InterOil Corp, which agreed last month to be acquired by Australia's Oil Search Ltd, said it had received an unsolicited offer from an unnamed bidder.

InterOil said on Thursday that it had agreed with Oil Search to engage in further talks with the third party.

In May, InterOil agreed to be acquired by Oil Search in a $2.2 billion deal.

http://www.reuters.com/article/us-interoil-m-a-offer-idUSKCN0ZG1HZ

Since the beginning of the U.S. fracking revolution, oil producers have struggled with a vexing problem: after an initial burst, crude output from new shale wells falls much faster than from conventional wells.

However, those well decline rates have been slowing across the United States over the past few years, according to data analysis provided exclusively to Reuters.

The trend, if sustained, would help ameliorate the industry’s most glaring weakness and cement its importance for worldwide production in years to come. It also helps explain shale drillers' resilience throughout the oil market's two-year slump.

While shale oil production revolutionized the oil industry over the past decade, bringing abundance of global oil supplies, high costs and rapid production declines have been its Achilles heel. That is beginning to change thanks to technological innovation and producers' focusing less on maximizing output and more on improving efficiency and productivity.

According to data compiled and analyzed by oilfield analytics firm NavPort for Reuters, output from the average new well in the Permian Basin of West Texas, the top U.S. oilfield, declined 18 percent from peak production through the fourth month of its life in 2015. That is much slower than the 31 percent drop seen for the same time frame in 2012 and the 28 percent decline in 2013, when the oil price crash started.

The change was even more dramatic in North Dakota's Bakken shale, where four-month decline rates for new wells fell to 16 percent in 2015 from almost 31 percent in 2012. (Graphic:tmsnrt.rs/292ScGY)

A slower decline means producers need to drill fewer new wells to sustain output, said Mukul Sharma, professor of petroleum engineering at the University of Texas at Austin.

"You can have cash flow without having to expend a lot of capital."

The recent decline rates mark a dramatic improvement from first-year 90 percent declines in the early years of the shale boom that made some investors question the sector's long-run viability.

NEW PHILOSOPHY

There are no 2016 figures yet, but oil executives expect the trend to continue this year and beyond.

Scott Sheffield, chief executive of Pioneer Natural Resources Co (PXD.N), a top Permian producer, credited improved fracking techniques for helping stabilize production, which shareholders rewarded by lifting Pioneer's shares up about 9 percent over the past year.

"We're exposing more of the reservoir and breaking it up so we don't get as sharp a decline," Sheffield told a recent energy conference.

Slower declines also reflect producers' more conservative approach to operating wells. In the early years of the hydraulic fracturing boom, high crude prices encouraged operators to boost initial production as much as possible.

To do this, they would let wells flow fast by keeping pressure low on the ground's surface. About seven years ago, however, some shale operators in Louisiana found this ultimately hurt production later on by causing rock fractures to shut.

Now, many operators maintain surface pressures higher, which limits initial flow rates and slows a well's decline rate.

http://www.reuters.com/article/us-usa-shale-declinerates-idUSKCN0ZH3RQ

Are we seeing the beginning of a trend? Yesterday MDN told you that after saying they would only drill a single Marcellus well and were curtailing production in the northeast, Eclipse Resources had turned that around and decided to drill 10-12 new wells, complete 24 wells and open up the spigots to shut-in wells once again.

Today we bring you news that Stone Energy has cut a new midstream gathering agreement with Williams and is returning some of their shut-in Marcellus wells to full production. Sure feels like things are beginning to look up!…

http://marcellusdrilling.com/2016/06/stone-energy-opens-marcellus-spigots-again-new-midstream-deal/

Triangle USA Petroleum Corp., an oil and gas explorer working one of the largest shale oil reservoirs in North America, filed for bankruptcy with a plan to restructure that will keep its parent company out of Chapter 11.

Triangle USA is active in the North Dakota and Montana regions of the Williston Basin, where it uses horizontal drilling and hydraulic fracturing. The company and its affiliates fell victim to the price slump that began in 2014, and bankruptcy proceedings were started “with the objective of realigning their capital structure with new market realities,” Chief Restructuring Officer John Castellano said in papers in Delaware federal court.

After several months of negotiations, the company reached an agreement with holders of 73 percent of its senior unsecured notes and plans to get out of bankruptcy by converting the debt into equity in a new, restructured business.

Parent Triangle Petroleum Corp. and an oilfield services affiliate, RockPile Energy Services LLC, weren’t included in Wednesday’s Chapter 11 filing. They and the bankrupt unit intend to keep operating, while a subsidiary that ceased operations this year, Ranger Fabrication LLC, was included in the bankruptcy case and will wind down under court protection.

As of the bankruptcy, Triangle USA had more than $689 million in long-term debt, including $308 million in a reserve-based revolving credit facility and $381 million in 6.75 percent 2022 senior unsecured notes. Those notes will be converted into equity and a new money rights offering for $100 million will be backstopped by participating noteholders, according to a company statement.

The arrangement still needs court approval and Triangle USA will keep negotiating with bank lenders in its senior reserve-backed facility and parties with which it has midstream agreements, including affiliates of joint venture Caliber Midstream Partners LP, according to the statement.

http://www.bloomberg.com/news/articles/2016-06-30/triangle-usa-petroleum-oil-and-gas-explorer-files-bankruptcy

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Earlier this week MDN told you that Southwestern Energy, a major Marcellus/Utica driller, has cut deals with its banks and debholders to extend out the due date on loans coming due.

Southwestern continues to aggressively manage its money and balance sheet. Yesterday the company announced it is floating $1.1 billion of new stock and plans to buy back outstanding notes (IOUs). We don’t pretend to understand why they would extend the due dates earlier this week and now attempt to buy back the IOUs. Perhaps it’s different sets of debt?

http://marcellusdrilling.com/2016/06/southwestern-floats-1-1b-of-new-stock-offers-to-buy-back-ious/

A Canadian court has overturned the approval of Enbridge Inc's Northern Gateway oil pipeline, again delaying a project fiercely opposed by environmentalists and many aboriginal groups.

The Federal Court of Appeal ruled in a 2-to-1 decision released on Thursday that the government had failed in its duty to consult with aboriginal groups on the project and sent the matter back to Prime Minister Justin Trudeau's cabinet for a "prompt redetermination."

Calgary-based Enbridge said in a statement that it remains "fully committed" to building the C$7.9 billion ($6.1 billion) pipeline and that it was working with partners, including aboriginal groups who support the project, to determine the next steps.

Canada's former Conservative government in 2014 approved Northern Gateway, which would carry oil from the Alberta oil sands to a port in British Columbia for export. Its construction was subject to more than 200 conditions.

After the approval, numerous British Columbia aboriginal communities, along with environmental groups, filed lawsuits seeking to overturn the decision.

In its 153-page judgment, the court determined that Canada's consultation with aboriginal communities, also known as First Nations, was "brief, hurried and inadequate." It said the government failed to grapple with their concerns and had not shown any intention to correct any errors or omissions in the original regulatory panel review.

"Missing was a real and sustained effort to pursue meaningful two-way dialogue. Missing was someone from Canada's side empowered to do more than take notes, someone able to respond meaningfully," the judges wrote.

The court also noted that it would have taken little time and effort to meaningfully engage with First Nations, but that it was not done. Trudeau's cabinet will now have to fulfill that duty before a new permit can be issued.

In April, Trudeau said he opposed the pipeline. His government has promised a moratorium on oil tanker traffic along the coast of northern British Columbia, a policy seen making the pipeline unfeasible.

In a statement Thursday, the government said it will review the ruling before determining next steps and reaffirmed its vow to build a "nation-to-nation" relationship with aboriginals.

The court's decision was heralded by project critics, who said it shuts the door on the 1,177-km (730-mile) pipeline.

"This pipeline will never be built. This is a victory," Sven Biggs, a representative of one of the environmental groups in the lawsuit, said in a statement.

http://www.reuters.com/article/enbridge-inc-pipeline-idUSL1N19M1IW