Oil bulls trying to push the crude market higher finally waved the white flag on Wednesday, triggering the biggest rout in a year, on concerns that stubbornly high inventory levels would persist despite supply cuts.

Prices had been locked in the tightest trading range in over a decade as traders and speculators piled into bets that oil prices would rise after the world's top producers cut output.

For weeks, they shrugged off record high inventories in the United States until on Wednesday, the market finally blinked.

Global oil benchmark, Brent and U.S. crude's West Texas Intermediate prices plunged more than 5 percent - the biggest drop since February 2016 - an unwelcome reminder of the darkest days of a two-year price war that left many U.S. shale producers with beleaguered balance sheets.

The move also pushed trading volumes to the highest since early December with over 430,000 contracts in Brent crude for May delivery and more than 911,000 contracts of WTI for delivery in April changing hands.

Industry players were divided on whether the price slide would continue or be short-lived given producers' adherence to a pledge to rein in output and prop up prices that have languished for over two years owing to a glut.

"The high level of uncertainty that has kept the oil complex trading in a relatively narrow trading range since late last year has been replaced, at least for the moment, by a bearish market sentiment," said Dominick Chirichella, senior partner at the Energy Management Institute in New York.

"The discussion will now center around whether or not Saudi Arabia is willing to give back market share to U.S. producers ... or are they ready for yet another round of the market share war."

So far, there has been no indication that Saudi and OPEC would extend the cuts beyond what is announced or allow the U.S. to claw some of its market share.

Suhail bin Mohammed al-Mazrouei, the energy minister for the United Arab Emirates told Reuters on the sidelines of an industry conference in Houston that the plunge in oil prices was temporary and that prices would rise as OPEC complies with output cuts.

Still, the rise in inventories was "a worry", he admitted.

Despite record exports in U.S. crude oil, inventories have ballooned to a new high week after week, threatening a speedy rebalancing of the market.

Saudi Oil Minister Khalid al-Falih even admitted on Tuesday inventory drawdowns were taking longer than he had expected for the first two months of the year.

The crash on Wednesday also tested key technical levels of support established this year and dropped below their 100-day moving averages - a key metric for chart watchers - for the first time since the OPEC deal was announced.

"The move down is in oversold territory, but otherwise, there is very little evidence that it will end," said Dean Rogers, senior analyst at Kase & Company said of WTI.

A small upward correction might take place first, but odds strongly favor a continued decline toward the next major target at $48, he said, adding that for Brent, the move lower is poised to continue to at least $52.60 and likely $51.60 and lower over the next few days.

But for the long term, most market participants continue to remain bullish.

Trade in options - that give the holder the right to buy or sell at a specific price - signaled that the market does not expect prices to move much lower than current levels.

"Their (OPEC's) response may very well be a continuation of co-operation to limit their oil production, perhaps for a little longer than they had hoped and this should help keep a floor under oil prices," said Fawad Razaqzada, technical analyst at forex.com.

"Indeed, despite today's sharp sell-off, I remain bullish on oil and still expect to see $60-$70 a barrel by the year end."

http://www.reuters.com/article/global-oil-selloff-idUSL2N1GM021

Early in the morning, small groups of armed pick-up trucks raced across the desert towards some of Libya's biggest oil export terminals.

A previous attempt by the Benghazi Defence Brigades (BDB) to capture the ports had failed. But the attack last Friday caught the eastern-based Libyan National Army (LNA) by surprise.

The LNA's withdrawal from the ports of Es Sider and Ras Lanuf has dented its claims to military superiority, dimming the prospects for its leader, Khalifa Haftar, to expand his power.

It also opens up a new front between factions battling on and off for power in Libya since 2014, throwing efforts to unite the country and rebuild oil production into deep uncertainty. The North African state is exempt from a recent OPEC deal to limit global supply, and had more than doubled its output in recent months to about 700,000 barrels per day (bpd).

The LNA says it is mobilising for a counter attack, personally overseen by Haftar, against the BDB, the most recent armed faction to contest ports that should account for more than half of the OPEC member's exports.

The BDB says it is seeking a route to Benghazi, from where many of its members had fled in the face of LNA advances against Islamists and other opponents over the past two years.

It says it is fighting for families trapped or displaced by the LNA's military campaign, and to save Libya from a return to dictatorship and protect the revolution that toppled Muammar Gaddafi in 2011.

"Our main goal is to retake our city, we reject injustice and military rule," BDB commander Mustafa al-Sharksi told reporters. "When we rallied against Gaddafi, we wanted freedom, we wanted to build legitimate institutions, and leaders who would rule the country as those in the developed world do."

TRIBAL SUPPORT

Haftar, a former Gaddafi ally who casts himself as the man to save Libya from the chaos of militia rule, received a big boost in September when he took over Es Sider and Ras Lanuf, as well as Brega and Zueitina, two other terminals on the a strip of coast southwest of Benghazi known as the Oil Crescent.

Peeling away tribal support, Haftar ousted Ibrahim Jathran, a commander of Libya's Petroleum Facilities Guard (PFG) who had become unpopular for demanding money to end a port blockade.

The National Oil Corporation (NOC) in Tripoli was quickly invited to reopen the ports, and Libya's production more than doubled to 600,000 bpd.

The BDB has also said it will allow the NOC to operate freely, inviting in a PFG head appointed by the U.N.-backed Government of National Accord (GNA) in Tripoli.

Because Es Sider and Ras Lanuf were badly damaged in previous fighting and are operating at far lower levels than Zueitina and Brega, the initial impact on production has been limited. Total output stood at about 620,000 bpd on Thursday, NOC Chairman Mustafa Sanalla told Reuters.

But the BDB advance has put oil back at the centre of conflict and ambitious NOC plans to revive production may be stalled. The NOC had said it hoped to push output to more than 1 million bpd within months, on the way to pre-conflict output of 1.6 million bpd.

It will now require "pretty adroit footwork" by the NOC to sustain such a message, said John Hamilton, a director of Cross Border Information and an expert on Libyan energy.

"What this demonstrates is that Haftar is not able to provide security for the terminals," he said. "How can any ship owners or insurers or oil companies be confident of sending vessels to lift crude, even if Haftar regains them?"

MERCENARIES

After taking the ports seven months ago, the LNA repelled several attempted counter-attacks with air strikes, and carried out what it said were preemptive strikes against BDB mobilisation in the central desert region of Jufra.

Guards loyal to the LNA said the ports were well secured, and safe for foreign workers to return.

But when the BDB advanced again last Friday, LNA defences were quickly breached. LNA ground forces retreated towards Brega, about 115 km (70 miles) east of Ras Lanuf, and lost more than 30 men, according to medical sources.

There have been daily LNA strikes since, but their impact is unclear.

Sharksi said the BDB had air defence weaponry, claiming LNA pilots "are scared so they fly at high altitudes".

Fawzi Boukatef, a rebel leader in Benghazi in 2011 who is in contact with the BDB, said tribal support for Haftar, uncertain in parts of the east, had eroded in the Oil Crescent, and that mercenaries from southern Libya and sub-Saharan Africa who had been operating for the LNA had been bought off.

"Some were paid to leave the area and some were paid to fight on the other side," he told Reuters.

BENGHAZI SIEGE

The BDB, dismissed as al Qaeda-linked militants by the LNA, in fact have a wide support base, said Anas El Gomati, head of the Sadeq Institute, a Libyan think tank. They are motivated by the desire to get thousands of displaced families back to Benghazi, help those caught in a long siege in the district of Ganfouda, and by recent LNA air strikes in the desert.

"The attacks in Jufra certainly galvanized support for the BDB and created a rallying call against Haftar," he said.

Some BDB support comes from Misrata, the western port city that has been a source of military opposition to Haftar and where many displaced families from Benghazi have been living.

Though moderates in Misrata supported a U.N.-backed Government of National Accord (GNA) in Tripoli and have even been open to a deal with Haftar, fighting in the Oil Crescent risks strengthening hardliners on both sides, analysts say.

Haftar has shunned efforts to revive the U.N. peace process, while accusing elements within the GNA of supporting the BDB. A group of nearly 40 pro-Haftar members of Libya's eastern parliament voted this week to drop support from the GNA's leadership and withdraw from U.N.-mediated dialogue.

"From where we're sitting today, a deal looks highly unlikely," said Gomati.

http://www.reuters.com/article/libya-security-oil-idUSL5N1GM7YL

Australia Prime Minster Malcolm Turnbull on Thursday said warnings of potential shortfalls in gas was “very concerning”, and has called on the CEOs of east coast gas companies to address the threat to customers.

Turnbull’s comments come after the Australian Energy Market Operator (AEMO) released a report stating that a projected decline in gas production could result in a shortfall of gas-powered electricity generation (GPG) that will impact New South Wales, Victoria and South Australia, from the summer of 2018/19.

The AEMO’s ‘2017 Gas Statement of Opportunities (GSOO)’ report outlines that gas producers are expecting annual production to decline by 122 PJ, from 600 PJ in 2017 to 478 PJ in 2021.

Based on this information, AEMO advises that additional production will be required to meet the needs for GPG and residential, commercial and industrial gas consumers.

“At a time when liquefied natural gas (LNG) export is dominating demand and supply of gas in eastern states, strategic national planning of gas development has never been more critical for maintaining domestic energy supply adequacy across both gas and electricity sectors,” said AEMO COO Mike Cleary.

He noted that this tightening of the domestic gas market will have flow-on effects to the electricity sector unless there is an increase in gas supplies and development.

“Without this development to support GPG, modelling suggests average electricity supply shortfalls of between 80 GWh and 363 GWh may be experienced from 2018/19 to 2020/21. The scale of these shortfalls would breach the reliability standard which aims to supply at least 99.998% of electricity demand.”

Alternatively, Cleary noted that, if GPG gas requirements are supplied, then gas shortfalls of between 10 PJ/y and 54 PJ/y are projected in the residential, commercial, and/or industrial sectors from 2019 to 2024 in New South Wales, Victoria and South Australia.

“The 2017 GSOO highlights the increasing interdependencies between gas and electricity, and supply and demand, and the need for the Australian energy industry to have a holistic ‘single energy view’ to ensure long-term planning is carried out in the interests of consumers.

“Gas and electricity markets can no longer be viewed in isolation, as the overall convergence of energy markets in eastern and south-eastern Australia demands a single energy view from a national perspective. It requires holistic planning across the entire supply chain to enable investment decisions to be made in the long-term interests of consumers," said Cleary.

In the short term, AEMO has identified a range of potential industry responses that could mitigate both electricity and gas supply shortfalls; however, Cleary noted that these responses relied on appropriate market signals, and may be impacted on by considerations such as the retirement of coal-fired generators, and the direction of energy policy such as the existing moratoria on various gas developments across eastern Australia.

“Energy supply shortfalls could be mitigated in the short term by an increase in coal-fired generation and renewable energy output, combined with an uptake in technologies such as battery storage, together with increased gas production and the possibility of LNG exporters redirecting a small portion of their gas production to the domestic market,” he said.

“Gas producers have told us that there is potential scope to increase production from existing fields if incentivised, although the size of the increase is unknown and new fields may also need to be developed to meet projected demand," said Cleary.

The long-term outlook identifies that early investment in exploration and development programmes will be needed to bring uncertain and undiscovered resources to market in time to meet forecast increases in demand for gas.

Up to 5 500 PJ of additional production will need to be developed to meet projected demand post 2030, although the AEMO acknowledged that climate change policy, and emerging new technologies will influence future demand for GPG and the energy supply mix.

The Australian Petroleum Production and Exploration Association (Appea) said on Thursday that the AEMO’s warning is the consequence of many years of policy failure by successive state governments in Victoria and New South Wales.

APPEA CEO Dr Malcolm Roberts said the GSOO was the latest in a long list of credible warnings that eastern Australia was racing towards a gas supply cliff.

“For years now, politicians in Victoria and New South Wales have wilfully ignored these warnings,” Roberts said.

“AEMO, the Australian Consumer and Competition Commission, Appea, gas producers and their customers have all been demanding urgent action to increase gas supply.

“But the response has been policy indecision, restrictive regulations and politically motivated bans and moratoriums that have stymied exploration and development of local gas supplies.”

Roberts pointed to the Victorian Parliament’s decision this week to pass legislation effectively banning onshore gas development in that state.

“Clearly, the Victorian government cares more about Greens preferences than it does about jobs and cost of living pressures on families,” he said.

“Gas customers have watched with dismay as new projects – such as those proposed by Metgasco at Bentley, AGL at Gloucester and Santos at Narrabri in New South Wales, and Lakes Oil and Gippsland projects in Victoria – have been either blocked, withdrawn or delayed.

“These projects would have added significantly to east coast gas supply. Fortunately, there is activity in other jurisdictions. Project Charlie and the Western Surat project in Queensland, the Sole project in Commonwealth waters offshore from Victoria and the Southern Cooper Basin gas project in South Australia are all moving forward.

“Several east coast gas producers have also confirmed as recently as today that they have available gas that they can and do sell into the domestic market.”

Roberts said onshore exploration was at its lowest level in more than three decades. Recent Australian Bureau of Statistics data showed onshore exploration expenditure falling by 64% in the past year.

“Australia has more than enough gas to meet its export and domestic needs. It just needs the political will to develop it,” he said.

http://www.miningweekly.com/article/turnbull-concerned-by-impending-australia-gas-supply-cliff-2017-03-09

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Mining major BHP Billiton has estimated that some 30-million barrels a day of new oil supply would be needed by 2025, to cater to global demand.

The company’s president for petroleum operations, Steve Pastor, said in Texas this week that based on the near a near 1% a year global demand growth, and a 3% to 4% natural field declines, the world would need nearly one-third of its current global demand in new supply.

“Oil shale plays a part in filling the gap, but its not enough,” Pastor said this week.

“We think the core oil shale positions, the sweet spots, are likely to be developed first and fairly rapidly over the next five to seven years. Away from the sweet spots, oil shale development is inevitably higher on the cost curve and typically a lot gassier.”

Pastor said that growth from core OPEC was also required, but would not be enough to meet demand on its own.

Pointing to data from the International Energy Agency, Pastor noted that the call on OPEC countries would rise from 32.2-million barrels of oil a day in 2016 to 34.3-million barrels of oil a day in 2020, to 35.8-million barrels of oil a day in 2022.

The International Energy Agency concluded that more investment was needed in oil production capacity to avoid the risk of a sharp increase in oil prices towards the end of its 2022 outlook period.

Pastor noted that while BHP agreed that new conventional production was needed, the most significant opportunity for growth was with the deepwater developments.

“We believe top tier players who are particularly good at deep-water exploration and development can develop superior margins and value. But being competitive for capital requires not only good geology, geoscience and engineering to de-risk plays and prospects, it also requires attractive, competitive and stable fiscal terms that offer a reasonable, risk considered, return on investment.”

Pastor said that cost and capital efficiencies were increasingly important, and would play a key role in deepwater as they have in lowering breakeven prices in shale.

http://www.miningweekly.com/article/bhp-sees-massive-oil-demand-ahead-2017-03-09

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London-based Ophir Energy on Thursday said it still expects to make a final investment decision on its Fortuna FLNG project in Equatorial Guinea in mid-2017.

Ophir and its partner, OneLNG, a joint venture between Golar LNG and Schlumberger, had “advanced the Fortuna FLNG project towards FID,” Ophir said in its 2016 results report.

Ophir and One LNG signed a deal back in November to form a joint operating company to develop the Fortuna FLNG project.

“Since announcing the JV in November 2016 we have made good progress against the remaining milestones. The Umbrella agreement between the Fortuna JV and the Government of Equatorial Guinea is expected to be signed during the first quarter this year. This defines the legal and fiscal framework for the project,” said Nick Cooper, Chief Executive of Ophir Energy.

“A term sheet has been signed for the provision of the debt facility with a consortium of Chinese banks. We have now moved to the documentation phase and expect to close the facility during the second quarter of2017,” he added.

Cooper said that talks with offtakers “remain on-going and are expected to be closed out imminently.”

http://www.lngworldnews.com/ophir-fortuna-flng-remains-on-schedule-for-fid-in-mid-2017/

UK-based energy giant and LNG player BP will shut down the second liquefaction train at the Tangguh LNG plant in Indonesia for two months.

Train 2 will be shut down for maintenance, Reuters reports, citing Dharmawan Samsu, BP’s Indonesia country head.

The production capacity of the second liquefaction train is 3.8 million tons of LNG per year.

BP, the operator of the Tangguh LNG project, together with other partners reached a final investment decision to build a third train at the facility.

The third train will add additional 3.8 mtpa of production capacity to the existing facility, bringing total plant capacity to 11.4 mtpa.

In 2016, the plant shipped a total of 119 LNG cargoes, the highest ever since the production started in 2009.

The Tangguh LNG facility is located in Papua Barat Province of Indonesia and consists of offshore gas production facilities supplying two 3.8mtpa liquefaction trains that have been in operation since 2009.

Other partners in the Tangguh production sharing contract are MI Berau (16.30%), CNOOC Muturi (13.90%), Nippon Oil Exploration (Berau) (12.23%), KG Berau Petroleum and KG Wiriagar Petroleum Ltd (10.00%), Indonesia Natural Gas Resources Muturi (7.35%), and Talisman Wiriagar Overseas (3.06%).

http://www.lngworldnews.com/indonesia-tangguh-lng-train-2-to-shut-down-for-maintenance/

Exxon Mobil Corp said on Thursday it would buy a 25 percent stake in a natural gas-rich block, offshore Mozambique, from Italy's Eni for $2.8 billion in cash.

The offshore gas reserves discovered by Eni in Mozambique are large enough to need a giant liquefied natural gas (LNG) export plant.

The east African nation's proximity to Asian and Middle Eastern growth markets could make it a highly lucrative project.

Eni will continue to lead a floating LNG project and all exploration and production in the block, Area 4, while Exxon will lead the construction and operation of natural gas liquefaction facilities onshore.

Eni sold 20 percent of its Area 4 license to China's CNPC for $4.2 billion in 2013, but oil and gas prices have more than halved since then.

Eni, which operates Area 4, currently holds a 50 percent indirect stake in the block through a 71.4 percent stake in Eni East Africa.

Galp Energia (GALP.LS), KOGAS (036460.KS) and Mozambique's state-owned energy firm ENH each own 10 percent in Area 4.

Upon closing of the deal, Eni and Exxon will each own a 35.7 percent stake in Eni East Africa, while CNPC will own 28.6 percent.

Reuters last year reported that Eni had wrapped up long-running talks to sell a multi-billion dollar stake in its planned Mozambique LNG development to Exxon.

http://www.reuters.com/article/us-exxon-mobil-eni-stake-idUSKBN16G1GF

The Singapore cracking margin against Dubai crude rebounded Wednesday from an 18-month low last week on the back of an uptick in light distillate cracks, S&P Global Platts data showed.

The Singapore cracking margin against Dubai was at $3.27/b on Wednesday, having rebounded from an 18-month low of $2.19/b on March 2, the data showed.

The last time the spread was lower was on August 31, 2015 when it was at $1.78/b.

The Singapore cracking margin in March to-date averaged at $2.75/b, the lowest since July 2015 when it was at $2.25/b. In comparison, the Singapore cracking margin averaged $5.75/b in February.

The spread widened on Wednesday as Asian gasoline crack rebounded from a record low following a drawdown in US gasoline stocks.

The spread between physical benchmark FOB Singapore 92 RON gasoline crack against front-month ICE Brent crude futures rebounded to $9.03/b Wednesday, Platts data showed.

The crack had fallen to a five-month low of $7.26/b on March 2 on excess supply and a slowdown in demand. It was last lower on October 7 last year at $7.14/b.

The uptick in the Asian gasoline crack was supported by the more-than-expected draw in stocks in the US.

US gasoline stocks fell 6.555 million barrels to 249.334 million barrels in the week ended March 3, data from the US Energy Information Administration showed. Analysts were looking for a draw of 2 million barrels.

Gasoline inventories shrank despite US refineries holding at a stable run rate of 85.9% for the week ended March 3, compared with 86% the week before.

Platts margin data reflects the difference between a crude's netback and its spot price.

Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.

http://www.platts.com/latest-news/oil/singapore/singapore-cracking-margin-rebounds-from-18-month-27786927

Privately-run conglomerate CEFC China Energy has approached several independent Chinese oil processors seeking to acquire its first domestic refinery operation, its next move towards becoming a global integrated oil player.

New details of CEFC's attempts to buy a refinery in China come less than three weeks after the little-known Shanghai-based firm announced its first major upstream oil investment, a $900 million deal for a 4 percent stake in an Abu Dhabi oilfield.

Talks with a handful of the small independent refiners known as "teapots" are just getting started, but CEFC's efforts are a rare early example of a private Chinese investor looking to cash in on Beijing's policy encouraging the small operators to venture into the global oil market to take on established state-run majors such as Sinopec Corp (0386.HK).

Chairman Ye Jianmin told a board meeting last July that CEFC aims to become a second Sinopec - China's second-biggest oil and gas major and Asia's largest refiner - by acquiring global assets and consolidating teapot refineries.

"CEFC has made it quite clear that it wants to invest in refining and held meetings with us," said one teapot executive who met with CEFC's Ye for such discussions.

"We'll need some time to deliberate and observe, as the company, ambitious as it is, lacks solid industry experience," said the executive, who declined to be named as the discussions were not public.

Ye's team has made frequent visits since mid-2016 to Shandong province, China's hub for teapots, courting at least four independent companies, including largest teapot refiner Shandong Dongming Petrochemical Group  and two small plants in the port city of Rizhao, according to three industry executives with knowledge of the meetings.

More recently CEFC has a new target, local government-backed Shandong Hengyuan Petrochemical Co, which owns a 70,000 barrels-per-day plant in the landlocked city of Linyi and a controlling stake in a refinery in Malaysia.

All the plants CEFC has approached so far have Beijing's greenlight to import crude oil, part of more than 20 local refiners that began emerging as market players in late 2015, helping to lift China's crude oil purchases to an all-time high last year while mopping up some of a global supply glut.

A refinery in the world's second-largest oil consumer would add to an asset network CEFC has built over the past two years - a Romanian refinery, service stations in Europe, an oilfield in Chad and the Abu Dhabi oilfield stake - said industry executives familiar with its strategy.

RELATED COVERAGE

FACT BOX CEFC China Energy's global energy, finance assets

"It's part of the company's organic expansion by looking at refining opportunities," a CEFC spokesman said in an email in response to a request for comment.

Wang Youde, chairman of Hengyuan Petrochemical, confirmed his company was approached by CEFC last year, but said he was not aware of any material progress in discussions.

Zhang Liucheng, vice president of Shandong Dongming, said his company also held meetings with CEFC for similar discussions, declining to give further details.

Alongside the talks, CEFC last month joined Dongming in a $566 million venture to build an oil terminal and storage farm in Shandong, facilities that are badly needed to ease logistics bottleneck gripping the teapots sector.

http://www.reuters.com/article/us-china-m-a-cefc-idUSKBN16H0G4

French energy company Engie has sold its British shale gas interests to petrochemicals firm Ineos for an undisclosed sum, the companies said on Thursday.

Engie was one of the first big energy companies to back Britain's nascent shale gas industry when it bought parts of Dart Energy's licenses, a company since then taken over by IGas, in 2013.

Thursday's deal builds on Ineos' position as Britain's largest shale gas company as it now has access to a shale gas area of more than 1.2 million acres. The company, which recently moved its headquarters from Switzerland back to Britain, wants to invest 1 billion pounds into shale gas which it bets on as a feedstock for its petrochemicals business.

Engie, on the other hand, said its retreat from British shale gas was in line with its strategy to focus more on energy infrastructure, like gas pipelines, and services.

"The decision was made following ENGIE Group's strategic review notably in response to commodity price declines," said a spokeswoman. Global oil prices have halved since hitting a peak in mid-2014 and have also weighed on gas prices.

As part of the deal, Ineos is taking over Engie's entire UK onshore exploration license portfolio, that consists of interests in 15 licenses, including seven in which Ineos had a previous participation.

"We are always going to be interested in acquiring additional acreage," Gary Haywood, chief executive of Ineos shale, told Reuters on the sidelines of an industry event.

He ruled out a large deal, however, saying the company's interests were already substantial.

Large amounts of shale gas are estimated to be trapped in underground rocks and the British government says it wants to exploit them to help offset declining North Sea oil and gas output, create some 64,000 jobs and help economic growth.

But so far only one shale gas well has been fracked and progress has been slow over the past years due to regulatory hurdles and public protests. Environmental groups are concerned that fracking could contaminate groundwater and that it is incompatible with fighting climate change.

Shale gas fracking firms IGas (IGAS.L) and Cuadrilla confirmed the changes in license ownership in which they are also involved.

http://www.reuters.com/article/britain-shale-engie-ineos-idUSL5N1GM3AO

Lessons learned from the shale revolution, combined with excellent geology, will allow Permian basin operations to grow and maintain profitability at a mere $40/bbl, according to two of the region’s top operators—Occidental Petroleum and Pioneer Natural Resources.

“Right now, a lot of producers have significant opportunities that are economical to develop under $40/bbl,” Occidental President and CEO Vicki Hollub the CERAWeek crowd on Tuesday afternoon. She said that Permian production could eventually grow to 5 million bopd. “I just think it is going to depend on oil prices. It will be there one day, it is just a matter of how fast it can get there.”

Occidental began trimming its business three years ago to focus on five areas that gave the company its best returns. The Permian was one of the five areas, along with five in the Middle East and one in South America. The company considers the Permian one of its core areas, Hollub said.

“Today, you can grow the company at 5%, at $40-oil,” said Pioneer Executive Chairman and CEO Scott Sheffield. He compared the potential of the Permian to Ghawar field in Saudi Arabia. “You could easily see 8 to 10 MMbpd out of the Permian by 2027.” He went on to say that the Permian could contain an estimated total of 160-170 Bbbl of recoverable oil.

“People have to realize we are currently going after two to three benches in the Permian. There are 12 to 16 benches we can go after in various price environments,” Sheffield said. “When you have 12 to 16 benches in the Permian, if the service companies can figure out how we can drill six to eight at one time, and frac them all at once, it will take the Permian to a level we can’t believe. Instead of growing 500,000 bpd a year, it could easily reach 1 MMbpd each year.”

To fully take advantage of the Permian’s resources, he said additional infrastructure requirements would be needed, including many new pipelines, NGL lines, and natural gas lines to Mexico. “It’s the second largest associated gas field, and it’s going to go to 20 Bcfd,” he said. “We have to get our gas out of the Permian, and we have to keep a great relationship with Mexico to be able to do that.”

Sheffield said Pioneer is growing its Permian business at about 30% annually. “The Permian is going to be a big supplier to the world over the next few years.”

http://www.worldoil.com/news/2017/3/8/ceraweek-17-permian-has-room-to-grow-at-40bbl-says-oxy-pioneer?platform=hootsuite

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OPEC and the shale industry are interdependent. Both lose if they raise output too much, flood the market with more oil than can be consumed, and cause prices to crash.

Shale firms need OPEC to succeed in reducing global oil stockpiles and raising prices. And OPEC needs shale producers to be cautious in growing output to avoid undermining its policy of supply restraint.

The warmer relationship between OPEC and shale firms on display at the CERAWEEK conference hosted by IHS Markit in Houston this week has been building for some time.

OPEC's secretary-general said at the conference that the organization had "broken the ice" with shale oil producers and hedge funds who have become major players in the market.

Harold Hamm, head of one of the largest U.S. shale producers, said that industry would need to add output in a "measured way, or else we kill the market", suggesting no new dash for growth.

OPEC has also been briefing and consulting with hedge funds and physical oil traders to get their views on the supply-demand-price outlook and gauge their likely reaction to various potential supply policies.

OPEC’s interest in courting hedge funds and physical traders marks a recognition of the powerful role they play in molding expectations and driving futures prices in the short term.

OPEC, led by Saudi Arabia, has engineered a huge turn around in hedge fund views from bearish to bullish since September 2016 (“Saudi Arabia engineers big shift in oil market sentiment”, Reuters, Dec 14).

Hedge funds have accumulated a record bullish position in crude oil futures and options equivalent to more than 900 million barrels, which has helped push prices up by more than $10 per barrel since November.

In the past, OPEC has often blamed speculators for causing price volatility, but the organization is now anxious to cooperate with them to help achieve higher and more stable prices.

ANTITRUST

Even more ambitiously, OPEC seems to want some form of understanding with shale producers based on their mutual interest in avoiding another price collapse. The organization says it wants an "energy dialogue" with the United States and sees it as a "strategic partner in the rebalancing process".

But there are strict limits on how far shale producers can be co-opted into a system for managing the oil market and prices.

U.S. shale production is dispersed among dozens of companies which makes coordination with them exceptionally difficult because of the free-rider problem.

More importantly, under U.S. law shale companies are forbidden from attempting to coordinate production and prices among themselves or with OPEC.

There are severe civil and criminal penalties for sharing information about future output and prices let alone any attempt to divide market shares among producers (“The Antitrust Laws”, Federal Trade Commission, undated).

Even attempts to reach informal “understandings” among producers about the current and future state of the market are prohibited.

The Sherman Antitrust Act imposes criminal penalties of up to $100 million for a corporation and $1 million for an individual, along with up to 10 years in prison.

Shale producers cannot partner with OPEC to help manage oil supplies and prices -- even if both sides were interested in an accord.

More generally, the same antitrust prohibitions prevent OPEC from partnering with the major international oil companies to manage the development of offshore and other oil supplies.

BOOM-BUST

OPEC members, shale producers and the rest of the oil industry would all like to see a further rise in oil prices and avoid another crash.

OPEC members and Russia are loudly extolling the benefits of “compliance” with output cuts agreed in late 2016.

Shale firms are pledging to maintain their own financial “discipline” in expanding production and avoid flooding the market or developing unprofitable new oil wells.

Just when you thought it was safe to go all-in on energy stocks, credit, and commodities because, well, what could go wrong; crude's collapse in the last few days (amid record long speculators) has smashed Energy credit markets and sent high-yield bond prices cratering.

WTI Crude collapsed to a $48 handle at its lows today...

http://www.zerohedge.com/news/2017-03-09/energy-credit-risk-soars-crude-carnage-continues

Marathon Oil Corp. has agreed to sell off its Canadian oil sands business for $2.5 billion, jettisoning an expensive segment that harvested about a tenth of its oil, the company said Thursday.

The sale to Royal Dutch Shell and Canadian Natural Resources, expected to close in mid-2017, would cut a quarter of the company’s operating expenses this year.

“Historically, our interest in the Canadian oil sands has represented about a third of our company’s other operating and production expenses, yet only about 12 percent of our production volumes,” Marathon President and CEO Lee Tillman said in a written statement.

Separately, the Houston driller also agreed to snap up 70,000 net acres in the Permian Basin in West Texas for $1.1 billion in cash. The transaction with private company BC Operating, includes 51,500 acres in the Northern Delaware basin in New Mexico.

All told, the Texas and New Mexico land has about 5,000 feet of “oil-rich stacked pay,” Tillman said, referring to the multiple subterranean layers of oil-soaked rock that have attracted drillers to the region despite high land prices. That deal is expected to close in the second quarter.

The transaction puts the value of the Permian Basin land at $13,900 per acre.

http://fuelfix.com/blog/2017/03/09/marathon-oil-jettisons-canadian-oil-buys-permian-basin-land/

Private equity firms Pine Brook and Riverstone Holdings agreed to invest as much as $600 million in a newly created oil and natural gas explorer in Texas’s energy-rich Permian Basin.

The firms will give Midland, Texas-based Admiral Permian Resources LLC a line of equity to purchase leaseholds and bankroll joint ventures and other deals in west Texas and southeastern New Mexico, Pine Brook co-President Rich Aube said in a phone interview.

Denzil West, a former president of Midland-based Reliance Energy Inc., which in October sold the bulk of its exploration assets to Concho Resources Inc. for $1.7 billion, is Admiral’s chief executive officer.

Private equity investing in U.S. oil and gas properties has dropped sharply since a supply glut triggered a free fall in oil prices. Since September oil has ranged from $43 to $55 a barrel, just over half its peak in June 2014. Last year in the sector, North American private equity deal volume was $11.7 billion, 60 percent less than in 2014, according to data compiled by Bloomberg.

Despite that, private equity firms and oil companies have poured billions of dollars into the Permian over the last year, vying for position in an oilfield so prolific it’s generated profits even during the worst crude-market slump in a generation. The frenzy has pushed lease prices as high as $60,000 an acre in some cases.

Competitive Basin

Exxon Mobil Corp. agreed in January to pay as much as $6.6 billion to more than double its holdings in the Permian. On Thursday, Houston-based Marathon Oil Corp. said it would spend $1.1 billion to acquire 70,000 acres in the New Mexico portion of the play.

“People have focused on the Permian to the exclusion of lots of other basins, because it’s the best resource in the U.S.,” Aube said. “The economics have been working, and they’re getting better.”

Aube observed that, because of the steep cost of acreage there, making investments work takes substantial operating savvy.

“It’s a very competitive basin, and you really need to be partnered with the best management teams to be successful,” said Aube.

New York-based Pine Brook, led by CEO Howard Newman and co-Presidents Aube and William Spiegel, oversees about $6 billion in clients’ capital.

Riverstone, led by founders Pierre Lapeyre and David Leuschen, has raised more than $34 billion since its start in 2000 for buyout and growth investments in energy and power companies.

https://www.bloomberg.com/news/articles/2017-03-09/pine-brook-riverstone-to-invest-up-to-600-million-in-permian