As OPEC officials gathered this week to formulate a long-term strategy, few in the room expected the discussions would end without a clash. But even the most jaded delegates got more than they had bargained with.

"OPEC is dead," declared one frustrated official, according to two sources who were present or briefed about the Vienna meeting.

This was far from the first time that OPEC's demise has been proclaimed in its 56-year history, and the oil exporters' group itself may yet enjoy a long life in the era of cheap crude.

Saudi Arabia, OPEC's most powerful member, still maintains that collective action by all producers is the best solution for an oil market that has dived since mid-2014.

But events at Monday's meeting of OPEC governors suggest that if Saudi Arabia gets its way, then one of the group's central strategies - of managing global oil prices by regulating supply - will indeed go to the grave.

In a major shift in thinking, Riyadh now believes that targetting prices has become pointless as the weak global market reflects structural changes rather than any temporary trend, according to sources familiar with its views.

OPEC is already split over how to respond to cheap oil. Last month tensions between Saudi Arabia and its arch-rival Iran ruined the first deal in 15 years to freeze crude output and help to lift global prices.

These resurfaced at the long-term strategy meeting of the OPEC governors, officials who report to their countries' oil ministers.

According to the sources, it was a delegate from a non-Gulf Arab country who pronounced OPEC dead in remarks directed at the Saudi representative as they argued over whether the group should keep targeting prices.

Iran, represented by its governor Hossein Kazempour Ardebili, has been arguing that this is precisely what OPEC was created for and hence "effective production management" should be one of its top long-term goals.

But Saudi governor Mohammed al-Madi said he believed the world has changed so much in the past few years that it has become a futile exercise to try to do so, sources say.

"OPEC should recognise the fact that the market has gone through a structural change, as is evident by the market becoming more competitive rather than monopolistic," al-Madi told his counterparts inside the meeting, according to sources familiar with the discussions.

"The market has evolved since the 2010-2014 period of high prices and the challenge for OPEC now, as well as for non-OPEC (producers), is to come to grips with recent market developments," al-Madi said, according to the sources.

Dispensing with price targets represents a massive change in Saudi thinking. This is now being driven largely by 31-year-old Deputy Crown Prince Mohammed bin Salman, who took over as the ultimate decision maker of the country's energy and economic policies last year.

When oil was viewed as scarce, the kingdom thought it had to maximise its long-term revenues even if that meant pumping fewer barrels and yielding market share to rival producers, according to several sources familiar with the Saudi thinking.

With the importance of oil declining, Riyadh has decided it is wiser to prioritise market share, the sources say. It believes it will be better off producing more at today's low prices than reducing output, only to sell the oil for even less in the future as global demand ebbs.

On top of this, Riyadh has pressing short-term needs including tackling a budget deficit which hit 367 billion riyals ($97.9 billion) or 15 percent of gross domestic product in 2015.

"The oil industry is, relatively speaking, not a growth industry any more," said one of the sources familiar with the Saudi views inside the OPEC governors' meeting.

In the past, low oil prices used to push global demand much higher but today's rising efficiency of motor vehicles, new technology and environmental policies have put a lid on growth.

Despite record low prices in the past year, demand is not expected to grow by more than 1 million barrels per day in 2016, just one percent of global demand.

One thing is guaranteed: the kingdom will not go back to the old pattern of cutting output any time soon to support prices for the benefit of all producers, Saudi sources say.

"The bottom line is that there will be no free riders any more," al-Madi said at Monday's meeting. "Some OPEC members should 'walk the talk' first," he told his colleagues.

Even Riyadh's rivals doubt it will perform any U-turn. "Saudi Arabia doesn't give a damn about OPEC any more. They are after U.S. shale, Canadian oil sands and Russia," a non-Gulf OPEC source said.

http://www.reuters.com/article/saudi-oil-opec-idUSL5N1826DI

Saudi Arabia was said to raise its pricing for June oil sales to Asia by the most since April 2015, in a sign that the world’s biggest exporter is expecting demand to recover as the global crude market rebalances.

State-owned Saudi Arabian Oil Co. increased its official selling price for Arab Light crude to Asia by $1.10 a barrel to 25 cents more than regional benchmarks Oman and Dubai, said people with knowledge of the matter who asked not to be identified because the information is confidential. The company, known as Saudi Aramco, was predicted to raise its pricing for the grade by 65 cents a barrel, according to the median estimate in a Bloomberg survey of five refiners and traders.

The Middle East producer is increasing the cost of its supplies to the largest oil-consuming region amid unplanned outages and disruptions that have helped curb a global oversupply and as signs of demand emerge. Benchmark prices have rallied more than 60 percent since mid-February, rebounding from the biggest crash in a generation after a global glut prompted by the U.S. shale boom led to an industry downturn.

Arab Light’s price to Asia for June is the highest since September 2015, and it’s only the third time the grade is being sold at a premium to the benchmarks since Saudi Arabia in November 2014 launched OPEC on its market strategy. The group continued to pump supplies even as prices cratered, forcing higher-cost production elsewhere to shut down.

“Refinery demand is expected to recover,” said Ehsan Ul-Haq, a senior analyst at industry consultant KBC Energy Economics in London. “Cargoes loaded in June will arrive in Asia in July, when demand will return after the seasonal turnaround period. Saudi Arabia may also use more crude at home in the summer, when electricity usage typically rises.”

Aramco will sell Arab Medium for June to Asia at $1.30 a barrel below benchmark prices, and Arab Heavy at a discount of $2.75 a barrel. The company also raised the premium for Arab Super Light crude to Asia by $1 a barrel to $3.95 a barrel over benchmarks, and Arab Extra Light by 80 cents a barrel to $2.60 a barrel.

The Organization of Petroleum Exporting Countries, of which Saudi Arabia is the largest producer, abandoned its production target at its most-recent meeting in December. The group has pumped more than the previous 30 million-barrel-a-day target since June 2014. Saudi Arabia produced 10.27 million barrels a day in April, according to data compiled by Bloomberg. OPEC is scheduled to meet June 2 in Vienna.

http://www.bloomberg.com/news/articles/2016-05-05/saudis-said-to-boost-oil-pricing-for-asia-by-most-in-14-months

Oil producers can expect to pump far more barrels from existing oil and gas fields than from fields yet to be discovered, two of BP plc’s energy analysts said Wednesday.

BP, the London-based supermajor, estimates that the world will need about 2.5 trillion barrels of oil equivalent to meet its energy needs through 2050. About 4.8 trillion in reserves can technically be recovered using today’s technology and another 2.0 trillion can be unlocked through enhanced recovery techniques, such as flooding wells older with water to drive more oil to the surface. Not all of those barrels will be tapped.

“If you apply the best technogly even in just conventional, giant fields than you can add lot of barrels over the next 20 years,” said David Eyton, group head of technology at BP.

The shift reflects the steady march of technology that has allowed producers to recover a greater percentage of oil from discovered reservoirs, as well as the addition of vast new reserves over the past decades from onshore shale basins.

Rrecoverable oil and gas reserves from already discovered fields vastly outnumber the roughly 700 billion additional barrels of oil and gas equivalent BP expects will be discovered through 2050.

The largest addition of extra reserves has already come in the past decade, when oil drillers figured out how to unlock the oil and gas locked away in shale by pumping water and sand into the ground at high pressure. The discovery has had producers examining shale reserves all over the world, and added a huge amount of on-paper barrels that could be pulled to the surface.

But shale oil has challenges too. The complex wells are often more expensive than more simple conventional ones. And while shale rocks exist all over the globe, the fracturing process has only been widely used in the U.S., and even there low prices have reduced activity to only a handful of the most productive basins. Producers are only currently able to pull a small amount of total oil and gas in the rock to the surface.

“All the shale oil and all the shale gas around the world is now potentially exploitable,” Eyton said. “So the amount of oil and gas you can go for has jumped hugely. But the recoveries from it are very low.”

The high cost of both unconventional reserves and exploring for new fields means that producers have been more willing to devote resources to making existing fields more productive. BP plc itself produces about 10 percent of the light oil pumped through enhanced oil recovery, or methods of squeezing more crude out of older oil wells.

The company said it’s expecting those techniques to get better as time goes on. BP said it’s experimenting with high-tech chemical solutions that can be pumped into wells to drive more oil to the surface, as well as advanced computer models that help the company decide how to drill wells that will bring the most oil out of a reservoir.

Ultimately, that could mean that companies hungry for oil could find it a better deal to go back to their old fields than to go searching the globe for new ones, Eyton said. Enhanced recovery is “beginning to challenge exploration as a lever on supply to the world’s consumption,” he said.

http://fuelfix.com/blog/2016/05/05/new-technology-offers-fresh-bounty-from-existing-fields-bp-says/?utm_source=twitterfeed&utm_medium=twitter

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Egypt will receive the first of five agreed shipments of liquefied natural gas (LNG) from Russia's Rosneft this month, an official at the state gas board EGAS told Reuters on Thursday.

Last year Egypt and Rosneft signed a memorandum of understanding for a slew of petroleum products as well as 24 LNG cargoes. Only five of the 24 initially agreed cargoes were later inked into a final deal.

"We're receiving the first shipments of LNG from Rosneft this month out of the five shipments that were agreed upon," said the EGAS official, declining to provide the value of the shipment or its size.

Once an energy exporter, Egypt has turned into a net importer because of declining oil and gas production and increasing consumption. It is trying to speed up production at recent discoveries to fill its energy gap as soon as possible.

Rosneft, Russia's biggest oil producer, does not produce its own LNG yet but plans to launch production jointly with Exxon Mobil after 2018.

http://af.reuters.com/article/commoditiesNews/idAFL3N1822JN

Israel will soon submit to Noble Energy Inc. and Delek Group Ltd. a proposal meant to unblock stalled development of the Leviathan natural gas field and allow exports to Egypt and Turkey, Energy Minister Yuval Steinitz said.

The proposal would be a “softer” version of the government’s offer to promise the energy explorers regulatory stability for 10 years, which Israel’s highest court struck down in March, Steinitz said Wednesday in an interview in his Jerusalem office.

“We are seeking to reach a solution soon, in a matter of weeks, no more than a couple of months,” he said. “I think we are very close and I think if both sides show some flexibility here, we can move forward.” He declined to go into details.

The absence of a regulatory framework has held up the development of Leviathan, Israel’s largest gas reserve, discovered in 2010, and hindered production at the smaller Tamar field. It also has blocked export deals and antagonized investors, making it harder for Texas-based Noble and units of Israel’s Delek to secure financing at a time when energy prices have tumbled.

Delek Group gained 1.3 percent at 4:55 p.m. in Tel Aviv. A company spokeswoman didn’t immediately return a request for comment and a Noble spokeswoman declined to comment on government discussions.

Exceeded Authority

Steinitz is leading a team of government officials trying to work around the court’s objection to the so-called stability clause, which it said exceeded the government’s authority. The government proposal that’s shaping up would provide Noble and Delek with some measure of stability, but not as much as the original commitment, Steinitz indicated.

“We will probably see some kind of softer stability commitment, but still significant,” he said. “I want to give them something which is softer but still substantial, which according to our experts has a reasonable chance not to be rejected by the court once again.”

Last month, Steinitz said the gas explorers may end up with a better deal as the government weighed incentives -- including debt guarantees and financial compensation -- for any damages resulting from regulatory changes. Asked on Wednesday whether those options were still on the table, he said he didn’t want to go into specifics.

Government legal advisers think such offers would be struck down by the court, according to a Finance Ministry official who wasn’t authorized to comment on record and spoke on condition of anonymity.

http://www.bloomberg.com/news/articles/2016-05-05/israel-near-domestic-gas-solution-turkish-deal-steinitz-says

For LNG buyers, 2040 is beginning to feel even further away.

Just a few years ago, faced with limited supply and relentless demand growth, liquefied natural gas buyers were happy to lock in contracts that ran through nearly the middle of the century, often paying prices linked to the cost of oil. Now, as the market moves deeper into oversupply, being tied to a producer for the next two decades is shifting from a blessing to a curse.

Less than 15 percent of long-term LNG supply contracts will expire in the next five years, according to data compiled by Bloomberg. Meanwhile, new projects in Australia and the U.S. are saturating the world with LNG, depressing spot prices 33 percent this year in Asia’s energy trading hub of Singapore, even as oil has risen about 20 percent. That’s giving buyers the incentive to try to renegotiate their deals with suppliers, according to analysts at Citigroup Inc. and Energy Aspects Ltd.

“Serious tensions will be seen in the market when oil starts transitioning to higher levels, driving contracted gas prices upwards,” Trevor Sikorski, an analyst with Energy Aspects in London, said by e-mail. “At the same time, the LNG spot market should stay low -- and that wider gap between the two prices will mean a number of buyers unhappy with that spread and this will drive calls for renegotiation.”

Buyers Emboldened

Petronet LNG Ltd. in December renegotiated its deal with Qatar’s RasGas Co., resulting in a drop by more than half of the price the Indian importer was paying. China National Petroleum Corp. wants new prices in its deal with Qatar, Chairman Wang Yilin said in March. Cnooc Ltd. Vice President Li Hui said last month the company is negotiating within its existing contract with Royal Dutch Shell Plc’s BG Group unit for 8.6 million tons of LNG a year.

Petronet’s negotiations allowed it to drop the price it’s paying for LNG to less than $5 per million British thermal unit, Oil Minister Dharmendra Pradhan said last week. The price was about $13 last year. In return, Petronet agreed to increase it’s purchases from Qatar.

“For India, achieving a low LNG import price at less than $5 per million Btu, based on prevailing oil prices through contract renegotiation, should embolden other parties to press for similar or even better terms,” Citigroup analysts including Ed Morse said in a research note Thursday. “Indeed, Asian buyers appear to be waiting for LNG sellers to acquiesce amid the looming oversupply.”

Breaking the Oil Link

About two-thirds of 160 long-term contracts with known commercial terms are linked to oil prices, according to data compiled by Bloomberg. That includes deals signed in 2009 in which Osaka Gas Co. Ltd and Chubu Electric Power Co. Inc. agreed to pay Chevron Corp. for LNG from the Gorgon project in northwest Australia based on Japanese crude import costs through 2040.

Buyers will try to change the basis of their deals from an oil-based index to a natural gas index such as Henry Hub in the U.S. to protect against an expected divergence in oil and gas prices, Sikorski said. The crash in energy prices has made other hedging options more affordable, said Melissa Stark, energy managing director and global LNG lead at Accenture. Importers can invest in midstream assets, like shipping and storage, or even buy stakes in U.S. shale projects and fields.

“There are more options for buyers,” Stark said by e-mail. “But with these options come more complexity, the need for trading and risk management capability.”

As some long-term contracts end, buyers will be looking to enter deals that are shorter in duration and smaller in volume, Gautam Sudhakar, IHS Inc.’s director of global LNG, said by e-mail. Projects that supply LNG for these expiring contracts are typically older and have paid off debts, so they will be able to add supply at competitive prices to the spot and short-term markets, he said.

http://www.bloomberg.com/news/articles/2016-05-05/lng-contracts-with-no-end-in-sight-spur-buyers-to-renegotiate

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Occidental Petroleum Corp.reported Thursday that its first-quarter income was $78 million or $0.10 per share, compared to loss of $218 million or $0.28 per share last year.

Core results for the first quarter of 2016 were a loss of $426 million or $0.56 per share, compared to profit of $31 million or $0.04 per share a year ago.

On average, 23 analysts polled by Thomson Reuters expected loss of $0.40 per share for the quarter. Analysts' estimates typically exclude special items.

Total oil and gas results reflected a loss of $388 million, compared to loss of $22 million last year.

Total net sales declined to $2.28 billion from last year's $3.10 billion. Analysts were looking for revenues of $2.35 billion.

Looking ahead, for fiscal 2016, the company production growth outlook increased to 4 to 6 percent with the same capital budget of $3.0 billion.

Previously, production growth was expected to be 2 to 4 percent from ongoing operations.

http://www.rttnews.com/2645408/occidental-petroleum-posts-wider-than-expected-loss-ups-production-growth-view.aspx

Canadian Natural Resources Ltd., the nation’s largest heavy-oil producer, reported a narrower first-quarter loss as production volumes met forecasts and costs dropped.

The net loss shrank to C$105 million ($81.9 million), or 10 cents a share, from C$252 million, or 23 cents, a year earlier, the Calgary-based company said Thursday in a statement. Excluding one-time items, the per-share loss from operations was 50 cents, beating the 58-cent loss expected by analysts, according to the average of 15 estimates compiled by Bloomberg.

Canadian Natural has lowered costs, slowed drilling and reduced salaries as it seeks to avoid job cuts in the slump, and remains focused on completing expansions of the Horizon oil-sands mining project this year and next. The company turned off some unprofitable natural-gas supplies in the first quarter and reduced heavy-oil volumes as it conducted repairs at its Kirby and Primrose East projects.

“Along with a cost-focused culture and track record of solid execution, one of the things we like about CNQ is its upstream growth and emerging free cash flow generation once its Horizon oil-sands expansion bears fruit in late 2017,” Greg Pardy, an analyst at RBC Dominion Securities in Toronto, wrote in an April 6 note. “CNQ’s most important potential catalyst revolves around operating performance at its Horizon oil-sands project.”

Production fell to the equivalent of 844,531 barrels a day in the quarter from 898,053 barrels a day a year earlier, according to the statement. West Texas Intermediate crude averaged $33.63 a barrel, down 31 percent from the same period last year.

http://www.bloomberg.com/news/articles/2016-05-05/canadian-natural-quarterly-loss-narrows-as-costs-fall-amid-rout

Chesapeake Energy Corp. on Thursday said its first-quarter loss narrowed as the embattled energy producer posted a smaller asset write-down than a year earlier as the result of low oil and gas prices.

Chesapeake also reached a deal to sell acreage in the Anadarko Basin Stack play to Newfield Exploration Co. for $470 million, part of Chesapeake’s broader efforts to improve its balance sheet and ride out the commodities downturn.

Shares rose 12% to $6.33 in recent premarket trading. The U.S. shale driller in February said was is aiming to raise as much a $1 billion this year by selling noncore assets.

Chief Executive Doug Lawler said the deal with Newfield “accelerates value from a portion of our undeveloped acreage that currently generates very little cash flow, giving us the ability to enhance current liquidity.”

”This transaction contributes substantially to achieving our previously announced target of an incremental $500 million to $1 billion of asset sales by year-end,” Mr. Lawler said. “We anticipate subsequent divestitures during the second and third quarters.”

Over all, Chesapeake Energy reported a first-quarter loss of $964 million, or $1.44 a share, compared with a year-earlier loss of $3.74 billion, or $5.72 a share. Excluding the asset write-down and other one-time items, the adjusted per-share loss was 10 cents. Revenue fell 39% to $1.95 billion.

Analysts polled by Thomson Reuters expected a loss of 10 cents a share on revenue of $2.55 billion.

The Oklahoma City company was co-founded in 1989 by the lateAubrey McClendon, who died in a car crash in March, a day after he was indicted on a charge of conspiring to rig bids on oil and gas leases in Oklahoma. A pioneer the shale energy boom, Mr. McClendon’s extreme risk-taking had caused him personal and professional financial hardships that spurred activist investors, including Carl Icahn, to oust him as Chesapeake’s chief executive in 2013.

http://www.wsj.com/articles/chesapeake-energy-quarterly-loss-narrows-on-smaller-write-downs-1462454889

Apache Corp's cost savings in the first three months of 2016 exceeded its own expectations and are likely to continue even if oilfield services costs rise, executives of the Houston-based oil and gas producer said on Thursday.

The cost cuts mean the company could achieve its goal of cash flow neutrality for 2016 with oil prices at $35 per barrel and natural gas prices at $2.35 per million British thermal units, Chief Executive John Christmann told investors on a conference call to discuss first quarter results.

The surprise savings come despite concerns that U.S. shale companies might have hit a wall in cost or productivity improvements, and are the latest sign that cost reductions could allow U.S. shale producers to keep drilling and pumping even if prices fail to recover significantly from a nearly two-year rout.

"Six quarters into the downturn, we are still achieving significant quarter on quarter cost improvements," Christmann said, noting that well cost reduction efforts "continued to exceed our expectations."

He said these cost reductions "are more than belt-tightening efforts in response to the downturn."

U.S. oil prices have fallen 60 percent since mid-2014 amid a global glut, but have rebounded since falling to nearly $26 per barrel in February, ending Thursday at about $44 a barrel. Natural gas futures settled at $2.08.

Christmann acknowledged skepticism around the sustainability of the company's cost-cutting hopes, particularly if demand for oilfield services rebounds, but said Apache's structural changes would help its bottom line "regardless of where oil prices and service costs go in the future."

Overall, the company's well costs in key North American onshore plays were 45 percent below 2014 levels, with oilfield with service cost savings making up half the decline and design and efficiency savings making up the other half.

Chief Financial Officer Steve Riney noted that capital costs in North American regions for the quarter were lower than the company had budgeted for, led by savings in the Permian basin.

Some steps that helped Apache save costs in the Permian included modifying fracture intensity and optimizing fluid levels.

http://www.reuters.com/article/apache-results-costs-idUSL2N1821VX

Rice Energy, one of the newest and brightest drillers in the Marcellus/Utica, released their first quarter 2016 update yesterday. 

The company reports production averaged 675 million cubic feet equivalent per day (Mmcfe/d) during 1Q16, a 53% increase over 1Q15 (and up 8% from 4Q15). 

On the financial side the company lost $21 million during 1Q16, versus making $152,000 in 1Q15. Pretty mild compared to most. 

During 1Q16 Rice drilled 11 new Marcellus wells and 8 new Utica wells. Good to see someone is still drilling!

http://marcellusdrilling.com/2016/05/rice-energy-1q16-prod-up-53-drilled-19-new-wells-lost-21m/

Eclipse Resources released their first quarter 2016 update yesterday.

Although Eclipse, a Marcellus/Utica pure play driller headquartered in State College, PA (but drilling mostly in Ohio), has curtailed or shut-in some of it’s production given low prices for gas, they still posted an impressive 26% increase in production in 1Q16 over 1Q15.

While we’ve heard of Prince and his “Purple Rain,” we hadn’t heard of Eclipse’s “Purpose Hayes”–which is a Utica well with an underground lateral reaching out 18,500 feet–3.5 miles!

During 1Q16 Eclipse drilled their Purple Hayes well in under 18 days. Amazing! Even more amazing–the well was completed with 124 frac stages. It is believed to be the longest onshore later well ever drilled. Kudos to Eclipse!

On the downside, the company lost $41 million in 1Q16…

http://marcellusdrilling.com/2016/05/eclipse-res-1q16-drills-longest-shale-well-ever-purple-hayes/